Page 1 of 54

**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 sectio n. (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: Cataly tic cracking units; fluid coking units; delayed coking units; catal yt ic reforming units; coke calcining units; asphalt blowing operations; blowdown sy stems; storage t anks; 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., h ydrogen plants that are owned or under the direct control of the refinery owner and operator). **§98.251 Reporting threshold.** You must report GHG emissions under this subpart if your facility contains a petroleum refineries process and the fac ility meets the requirements of either §98.2(a)(1) or (a)(2). **§98.252 GHGs to report.** You must report: (a) CO 2 , CH 4 , and N 2 O combustion emissions from stationary combustion units and from each flare. Calculate and report the emissions from stationary combu stion units under subpart CPage 2 of 54

of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C, except for emissions from combustion of fuel gas. For CO 2 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 CH 4 and N 2 O emissio ns from combustion of fuel gas, use the applicable procedures in §98.33(c) for the same tier methodology that was used for calculating CO 2 emissions. (Use the default CH 4 and N 2 O emission factors for “Fuel Gas” in Table C - 2 of this part. For Tier 3, use ei ther 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 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 an y point in the line supplying fuel gas or an upstream common pipe. (ii) The fuel gas line contains only vapors from loadin g or unloading, waste or wastewater handling, and remediation activities that are combusted in a thermal oxidizer or thermal incinerator.Page 3 of 54

(2) The combustion unit has a maximum rated heat input capacity of less than 30 mmBtu/hr and either of the following c onditions exist: (i) A flow meter is not installed at an y point in the line supplying fuel gas or an upstream common pipe; or (ii) The fuel gas line contains only vapors from loading or unloading, waste or wastewater handling, and remediation activities th at are combusted in a thermal oxidizer or thermal incinerator. (b) CO 2 , CH 4 , and N 2 O coke burn - off emissions from each catal yt ic cracking unit, fluid coking unit, and catal yt ic reforming unit under this subpart. (c) CO 2 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) CO 2 process emissions from each on - site sulfur recovery plant under this subpart. (e) CO 2 , CH 4 , and N 2 O emissions from each coke calcining unit under this subpart. (f) CO 2 and CH 4 emissions from asphalt blowing operations under this subpart. (g) CH 4 emissions from equipment leaks, storage tanks, loading operations, delayed coking units, and uncontrolled blowdown sy stems under this subpart. (h) CO 2 , CH 4 , and N 2 O emissions from each process vent not specifically included in paragraphs (a) through (g) of this section under this subpart. (i) CO 2 emissions from non - merchant hydrogen production process units (not including hydrogen produced from catal yt ic reforming units) following the calculation methodologies,Page 4 of 54

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 me thods 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. All gas discharged through the flare stack must be considered for the flare GHG emissions calculations with the exception of gas used for the flare pilots, which may

be excluded. (1) Calculate the CO 2 emissions according to the applicable requirements in paragraphs (b)(1)(i) through (b)(1)(iii) of this section. (i) Flow measurement . I f 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 continu ous 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 device, you must use engineering calculations, compan y records, or similar estimates of volumetric flare g as 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 weekl y, you must use the measured heat value or carbon content value in calculating the CO 2 emissions from the flare using the applicable methods in paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(B).Page 5 of 54

(A) If you monitor gas composition, calculate the CO 2 emissions from the flare using either Equation Y - 1a or Equation Y - 1b of this section. I f 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 weekl y values. (Eq. Y - 1a) where: CO 2 = Annual CO 2 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

measurem ents); the maximum value for n is 366 (for daily measurements during a leap ye ar). p = Measurement period index. 44 = Molecular weight of CO 2 (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/k g - mole). 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/kg - mole 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 m easurement values within the day to calculate a daily average.Page 6 of 54 (Eq. Y - 1b)

where: CO 2 = Annual CO 2 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 ye ar). 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 determ ine the average molecular weight of the flare gas during the measurement period and convert the mass flow to a volumetric flow. 44 = Molecular weight of CO 2 (kg/kg - mole). MVC = 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). 0.001 = Unit conversion factor (metric tons per kilogram, mt/kg). (%CO 2 ) p = Mole percent CO 2 concentration in the flare gas stream during the measurement

period (mole percent = percent b y volume). y = Number of carbo n - containing compounds other than CO 2 in the flare gas

stream. x = Index for carbon - containing compounds other than CO 2 . 0.98 = Assumed combustion efficiency of a flare (mole CO 2 per mole carbon). (%C X) p = Mole percent concentration of compound “x” in the flare gas stream during the

measurement period (mole percent = percent b y volume) CMNX = Carbon mole number of compound “x” in the flare gas stream (mole carbon

atoms per mole compound). E.g., CMN for ethane (C 2 H 6 ) is 2; CMN for propane (C 3 H 8 ) is 3. (B) If you monitor heat content but do not monitor gas composition, calculate the CO 2 emissions from the flare using Equation Y - 2 of this section. If dail y or more frequentPage 7 of 54

measurement data are available, you must use daily values when using Equation Y - 2 of this section; otherwise, use weekl y values. (Eq. Y - 2) Where: CO 2 = Annual CO 2 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 = Numbe r 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 ye ar). 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) p is 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 frequentl y than daily, use the arithmetic average of measurement values within the day

to calculate a dail y average. EmF = Default CO 2 emission factor of 60 kilograms CO 2 /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 weekl y, determine the quantity of gas discharged to the flare separatel y for periods of routine flare operation and for periods of start - up, shutdown, or malfunction, and calculate the CO 2 emissions as specified in paragraphs (b)(1)(iii)(A) through (b)(1)(iii)(C) of this section.Page 8 of 54

(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 sc f/day . (B) For periods of normal operation, use the average higher heating value measured for the fuel gas used as flare sweep or purge gas for the higher heating value of the flare gas. If higher heating value of the fuel gas is not measured, the higher h eating value of the flare gas under normal operations may be estimated from historic data or engineering calculations. (C) Calculate the CO 2 emissions using Equation Y - 3 of this section. (Eq. Y - 3) Where: CO 2 = Annual CO 2 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). Flare Norm = Annual volume of flare gas combusted during normal operations from company

records, (million (MM) standard cubic feet per ye ar, MMscf/ye ar). HHV = Higher heating value for fuel gas or flare gas from company records (British

thermal units per scf, Btu/scf = MMBtu/MMscf). EmF = Default CO 2 emission factor for flare gas of 60 kilo grams CO 2 /MMBtu (HHV

basis). n = Number of start - up, shutdown, and malfunction events during the reporting ye ar

exceeding 500,000 scf/day. p = Start - up, shutdown, and malfunction event index. 44 = Molecular weight of CO 2 (kg/kg - mole). 12 = Atomic weight of C (kg/kg - mole).Page 9 of 54

(Flare SSM ) 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 anal ys is results or

engineering cal culations for the event (kg/kg - mole). MVC = 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). (CC) p = Average carbon content of the flare gas, from analy sis results or engineering

calculations for the event (kg C per kg flare gas). (2) Calculate CH 4 using Equation Y - 4 of this section. (Eq. Y - 4) Where: CH 4 = Annual methane emissions from flared gas (metric tons CH 4 /year). CO 2 = Emission rate of CO 2 from flared gas calculated in paragraph (b)(1) of this

section (metric tons/year). EmF CH4 = Default CH 4 emission factor for “Fuel Gas” from Table C - 2 of subpart C of this

part (General Stationary

Fuel Combustion Sources) (kg CH 4 /MMBtu). EmF = Default CO 2 emission factor for flare gas of 60 kg CO 2 /MMBtu (HHV basis). 0.02/0.98 = Correction factor for flare combustion efficiency . 16/44 = Correction factor ratio of the molecular weight of CH 4 to CO 2 . f CH4 = Weight fraction of carbon in the flare gas prior to c ombustion 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 N 2 O emissions using Equation Y - 5 of this section. (Eq. Y - 5) Where: N 2 O = Annual nitrous oxide emissions from flared gas (metric tons N 2 O/year).Page 10 of 54

CO 2 = Emission rate of CO 2 from flared gas calculated in paragraph (b)(1) of this

section (metric tons/year). EmF N2O = Default N 2 O emission factor for “Fuel Gas” from Table C - 2 of subpart C of this

part (General Stationary

Fuel Combustion Sources) (kg N 2 O/MMBtu). EmF = Default CO 2 emission factor for flare gas of 60 kg CO 2 /MMBtu (HHV basis). (c) For catal yt ic 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. (1) If you operate and maintain a CEMS that measures CO 2 emissions according to subpart C of this part (General Stationary Fuel Combustion Sources), you must calculate and report CO 2 emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other catal yt ic cracking units and traditional fluid coking units must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of thi s part (General Stationary Combustion Sources), or follow the requirements of paragraphs (c)(2) or (3) of this section. (i) Calculate CO 2 emissions by following the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements fo r Tier 4 in subpart C of this part (General Stationary

Fuel Combustion Sources). (ii) For catal yt ic cracking units whose process emissions are discharged through a combined stack with other CO 2 emissions ( e.g., co - mingled with emissions from a CO boiler) you must also calculate the other CO 2 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 cataly

tic cracking unit or fluid coking unit as the d ifference in the CO 2 CEMS emissions and the calculated emissions associated with the additional units discharging through the combined stack.Page 11 of 54

(2) For catal yt ic cracking units and fluid coking units with rated capacities greater than 10,000 barrels per stre am day (bbls/sd) that do not use a continuous CO 2 CEMS for the final exhaust stack, you must continuously or no less frequently

than hourl y monitor the O 2 , CO 2 , and (if necessary) CO concentrations in the exhaust stack from the catal yt ic cracking unit rege nerator or fluid coking unit burner prior to the combustion of other fossil fuels and calculate the CO 2 emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section: (i) Calculate the CO 2 emissions from each catal yt ic cracking unit and fluid coking unit using Equation Y - 6 of this section. (Eq. Y - 6) Where: CO 2 = Annual CO 2 mass emissions (metric tons/year). Q r = Volumetric flow rate of exhaust gas from the fluid catal yt ic cracking unit

regenerator or fluid coking uni t burner prior to the combustion of other fossil fuels (dry standard cubic feet per hour, dscfh). %CO 2 = Hourly

average percent CO 2 concentration in the exhaust gas stream from the fluid catal yt ic cracking unit regenerator or fluid coking unit burner (perc ent by volume

—dry

basis). %CO = Hourly

average percent CO concentration in the exhaust gas stream from the fluid catal yt ic cracking unit regenerator or fluid coking unit burner (percent by volume

—dry

basis). When there is no post - combustion device, assume %CO to be zero. 44 = Molecular weight of CO 2 (kg/kg - mole). MVC = 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). 0.001 = Conversion factor (metric ton/kg). n = Number of hours in calendar year.Page 12 of 54

(ii) Either continuously

monitor the volumetric flow rate of exhaust gas from the fluid catal yt ic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels or calculate the volumetric flow rate of th is exhaust gas stream using either Equation Y - 7a or Equation Y - 7b of this section. (Eq. Y - 7a) where: Q r = Volumetric flow rate of exhaust gas from the fluid catal yt ic cracking unit

regenerator or fluid coking unit burner prior to the combustion of other fossil fuels (dscfh). Q a = Volumetric flow rate of air to the fluid catal yt ic cracking unit regenerator or

fluid coking unit burner, as determined from control room instrumentation (dscfh). Q oxy = Volumetric flow rate of oxygen enriched air to the fluid c atal yt ic cracking unit

regenerator or fluid coking unit burner as determined from control room instrumentation (dscfh). %O 2 = Hourly

average percent oxygen concentration in exhaust gas stream from the fluid catal yt ic cracking unit regenerator or fluid coki ng unit burner (percent by volume

—dry

basis). %O oxy = O 2 concentration in ox yg en enriched gas stream inlet to the fluid catal yt ic

cracking unit regenerator or fluid coking unit burner based on ox ygen purity specifications of the ox ygen suppl y used for enri chment (percent by volume

— dry basis). %CO 2 = Hourly

average percent CO 2 concentration in the exhaust gas stream from the fluid catal yt ic cracking unit regenerator or fluid coking unit burner (percent by volume

—dry

basis). %CO = Hourly

average percent CO co ncentration in the exhaust gas stream from the fluid catal yt ic 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. (Eq. Y - 7b)Page 13 of 54

where: Q r = Volumetric flow rate of exhaust gas from the fluid catal yt ic cracking unit

regenerator or fluid coking unit burner prior to the combustion of other fossil fuels (dscfh). Q a = Volumetric flow rate of air t o the fluid catal yt ic cracking unit regenerator or

fluid coking unit burner, as determined from control room instrumentation (dscfh). Q oxy = Volumetric flow rate of oxygen enriched air to the fluid catal yt ic cracking unit

regenerator or fluid coking unit b urner as determined from control room instrumentation (dscfh). %N 2,oxy = N 2 concentration in ox yg en enriched gas stream inlet to the fluid catal yt ic

cracking unit regenerator or fluid coking unit burner based on measured value or maximum N2 impurity specif ications of the ox ygen suppl y used for enrichment (percent by

volume

—dry

basis). %N 2,exhaust = Hourly

average percent N 2 concentration in the exhaust gas stream from the fluid catal yt ic 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 catal yt ic cracking unit or fluid coking unit exhaust gas, you must determine the CO 2 emissions resulting from the combustion of these fuels or other mat erials following the requirements in subpart C and report those emissions by following the requirements of subpart C of this part. (3) For catal yt ic cracking units and fluid coking units with rated capacities of 10,000 barrels per stream day

(bbls/sd) or l ess that do not use a continuous CO 2 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 continuousl y or no less frequentl y than daily monitor the O 2 , CO 2 , and (if necessary) CO concentrations in the exhaust stack from the cataly tic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels, you must calculate the CO 2Page 14 of 54

emissions accordi ng 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 dail y basis. (ii) If you do not monitor at least daily the O 2 , CO 2 , and (if necessary) CO con centrations in the exhaust stack from the catal yt ic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels, calculate the CO 2 emissions from each catal yt ic cracking unit and fluid coking unit using Equation Y - 8 of this section. (Eq. Y - 8) Where: CO 2 = Annual CO 2 mass emissions (metric tons/year). Q unit = Annual throughput of unit from compan y records (barrels (bbls) per ye ar,

bbl/y r). CBF = Coke burn - off factor from engineering calculations (kg coke per barrel of feed);

default for catal yt ic 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 CO 2 to C (kg CO 2 per kg C). (iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catal yt ic cracking unit or fluid coking unit exhaust gas, you must determine the CO 2 emissions resulting from the c ombustion 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. (4) Calculate CH 4 emissions us ing 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.Page 15 of 54 (Eq. Y - 9)

Where: CH 4 = Annual methane emissions from coke burn - off (metric tons CH 4 /year). CO 2 = Emission rat e of CO 2 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/ye ar). EmF 1 = Default CO 2 emission factor for petroleum coke from Table C - 1 of subpart C of

this part (Genera l Stationary Fuel Combustion Sources) (kg CO 2 /MMBtu). EmF 2 = Default CH 4 emission factor for “PetroleumProducts” from Table C - 2 of

subpart C of this part (General Stationary Fuel Combustion Sources) (kg CH 4 /MMBtu). (5) Calculate N 2 O 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. (Eq. Y - 10) Where: N 2 O = Annual nitrous oxide emissions from coke burn - off (mt N 2 O/year). CO 2 = Emission rate of CO 2 fro m 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/ye ar). EmF 1 = Default CO 2 emission factor for petroleum coke from Table C - 1 of subpart C of

this part (General Stationary Fuel Combustion Sources) (kg CO 2 /MMBtu). EmF 3 = Default N 2 O emission factor for “PetroleumProducts” from Table C - 2 of

subpart C of this part (kg N 2 O/MMBtu). (d) For fluid coking units that use the flexicoking design, the GHG emissions from the resulting u se of the low value fuel gas must be accounted for onl y once. T ypically, 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 par agraph (c)Page 16 of 54

of this section provided that you do not otherwise account for the subsequent combustion of this low value fuel gas. (e) For catal yt ic reforming units, calculate the CO 2 emissions using the applicable methods described in paragraphs (e)(1) throu gh (e)(3) of this section and calculate the CH 4 and N 2 O emissions using the methods described in paragraphs (c)(4) and (c)(5) of this section, respectivel y. (1) If you operate and maintain a CEMS that measures CO 2 emissions according to subpart C of this part (General Stationary Fuel Combustion Sources), you must calculate CO 2 emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other cataly tic reforming 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 (e)(2) or (e)(3) of this section. (2) If you continuously

or no less frequently

than daily

monitor the O 2 , CO 2 , and (if necessary) CO conc entrations in the exhaust stack from the cataly tic reforming unit catal ys t regenerator prior to the combustion of other fossil fuels, you must calculate the CO 2 emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this sec tion. (3) Calculate CO 2 emissions from the catal yt ic reforming unit catal ys t regenerator using Equation Y - 11 of this section. (Eq. Y - 11) Where: CO 2 = Annual CO 2 emissions (metric tons/year). CB Q = Coke burn - off quantity per regeneration cycle or measurement period from engineering estimates (kg coke/cycle or kg coke/measurement period).Page 17 of 54

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 k g coke); default = 0.94. 44/12 = Ratio of molecular weight of CO 2 to C (kg CO 2 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 CO 2 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 concentrati on of CO 2 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 CO 2 emissions acc ording to subpart C of this part, you must calculate CO 2 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 Co mbustion 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 CO 2 CEMS emissions and the calculated combustion emissions associated with the sulfur recovery plant final exhaust stack. Other sulfur recov ery plants must either install a CEMS that complies with the Tier 4 Calculation Methodology inPage 18 of 54

subpart C, or follow the requirements of paragraphs (f)(2) through (f)(5) of this section, or (for non - Claus sulfur recovery plants onl y) follow the requirements in paragraph (j) of this section to determine CO 2 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 yo u 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 for 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 facto r using limited measurement data or engineering estimates or use the default factor of 0.20. (4) Calculate the CO 2 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. (Eq. Y - 12) Where: CO 2 = Annual CO 2 emissions (metric tons/year). F SG = Volumetric flow rate of sour gas (including sour water stripper gas) fed to the

sulfur recovery

plant or the sour gas feed sent off - site for sulfur recovery (scf/year). 44 = Molecular w eight of CO 2 (kg/kg - mole).Page 19 of 54

MVC = 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). MF C = 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 meas ured data under paragraphs (f)(2) and (f)(3) of this section, respectively , then the annual CO 2 emissions calculated in paragraph (f)(4) of this section must be corrected to avoid double counting these emissions. You may use engineering estimates to perfor m this correction or assume that the corrected CO 2 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 CO 2 emissions according to subpart C of this part, you must calculate and report CO 2 emissions under this subpart by following the Tier 4 Calculation Methodology sp ecified 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 calcin ing 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 CO 2 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 f ollow the requirements of paragraph (g)(2) of this section.Page 20 of 54

(2) Calculate the CO 2 emissions from the coke calcining unit using Equation Y - 13 of this section. (Eq. Y - 13) Where: CO 2 = Annual CO 2 emissions (metric tons/year). M in = Annual mass of green coke fed to the coke calcining unit from facility records (metric tons/year). CC GC = Average mass fraction carbon content of green coke from facility measurement

data (metric ton carbon/metric ton green coke). M out = Annual mass of marketable petroleum cok e produced by the coke calcining unit from facility records (metric tons petroleum coke/year). M dust = Annual mass of petroleum coke dust removed from the process through the dust

collection sy stem of the coke calcining unit from facility records (metric t on petroleum coke dust/ye ar). 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. CC MPC = Average mass fraction carb on 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 CO 2 (kg/kg - mole). 12 = Atomic weight of C (kg/kg - mole). (3) For all coke calc ining units, use the CO 2 emissions from the coke calcining unit calculated in paragraphs (g)(1) or (g)(2), as applicable, and calculate CH 4 using the methods described in paragraph (c)(4) of this section and N 2 O emissions using the methods described in paragraph (c)(5) of this section. (h) For asphalt blowing operations, calculate CO 2 and CH 4 emissions according to the requirements in paragraph (j) of this section regardless of the CO 2 and CH 4 concentrations or according to the applicable provisions in para graphs (h)(1) and (h)(2) of this section.Page 21 of 54

(1) For uncontrolled asphalt blowing operations or asphalt blowing operations controlled either by vapor scrubbing or b y another non - combustion control device , calculate CO 2 and CH 4 emissions using Equations Y - 14 and Y - 15 of this section, respectivel y. (Eq. Y - 14) Where: CO 2 = Annual CO 2 emissions from uncontrolled asphalt blowing (metric tons

CO 2 /year). Q AB = Quantity of asphalt blown (million barrels per year, MMbbl/year). EF AB,CO2 = Emission factor for CO 2 from uncontrolled asphalt blowing from facility specific test data (metric tons CO 2 /MMbbl asphalt blown); default = 1,100. (Eq. Y - 15) Where: CH 4 = Annual methane emissions from uncontrolled asphalt blowing (metric tons

CH 4 /year). Q AB = Quantity of asphalt blown (million barrels per year, MMbbl/year). EF AB,CH4 = Emission factor for CH 4 from uncontrolled asphalt blowing from facilityspecific test data (metric tons CH 4 /MMbbl asphalt blown); default = 580. (2) For asphalt blowing operations controlled b y eithe r a thermal oxidizer , a flare, or other vapor combustion control device, calculate CO 2 using either Equation Y - 16a or Equation Y - 16b of this section and calculate CH 4 emissions using Equation Y - 17 of this section, provided these emissions are not alrea dy 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). (Eq. Y - 16a)Page 22 of 54

where: CO 2 = Annual CO 2 emissio ns from controlled asphalt blowing (metric tons CO 2 /y ear). 0.98 = Assumed combustion efficiency of the control device . Q AB = Quantity of asphalt blown (MMbbl/year). CEF AB = Carbon emission factor from asphalt blowing from facility- specific test data

(metric tons C/MMbbl asphalt blown); default = 2,750. 44 = Molecular weight of CO 2 (kg/kg - mole). 12 = Atomic weight of C (kg/kg - mole). (Eq. Y - 16b) where: CO 2 = Annual CO 2 emissions from controlled asphalt blowing (metric tons CO 2 /y ear). Q AB = Quantity of asphalt blown (MMbbl/year). 0.98 = Assumed combustion efficiency of the control device . EF AB,CO2 = Emission factor for CO 2 from uncontrolled as phalt blowing from facilityspecific test data (metric tons CO 2 /MMbbl asphalt blown); default = 1,100. CEF AB = Carbon emission factor from asphalt blowing from facility - specific test data

(metric tons C/MMbbl asphalt blown); default = 2,750. 44 = Molecular weight of CO 2 (kg/kg - mole). 12 = Atomic weight of C (kg/kg - mole). (Eq. Y - 17) where: CH 4 = Annual methane emissions from controlled asphalt blowing (metric tons

CH 4 /year). 0.02 = Fraction of methane uncombusted in the controlled stream based on assumed

98% combustion efficiency .Page 23 of 54

Q AB = Quantity of asphalt blown (million barrels per year, MMbbl/year). EF AB,CH4 = Emission factor for CH 4 from uncontrolled asphalt blowing from facilityspecific test data (metric tons CH 4 /MMbbl asphalt blown); default = 580. (i) For each delayed coking unit , calculate the CH 4 emissions from delayed decoking operations (venting, draining, deheading, and coke - cutting) according to the requirements in paragraphs (i)(1) through (i)( 5 ) . (1) Determine the typical dry mass of coke produced per cycle from company records of the mass of coke produced by the delayed coking unit. Alternatively , you may estimate the typical dry mass of coke produced per cycle based on the delayed coking unit vessel (coke drum ) dimensions and ty

pical coke drum outage at the end of the coking cycle using Equation Y - 18a of this section. 

##   2 coke bulk drum outage π D M ρ H H 4  

         (Eq. Y - 18a) Where: M coke = Ty

pical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (metric ton s /cycle). ρ bulk = Bulk coke bed density (metric tons per cubic feet; mt/ft 3 ). Use the default value

of 0.0191 mt/ft 3

. H drum = Internal height of de layed coking unit vessel (feet). H outage = Ty

pical distance from the top of the delayed coking unit vessel to the top of the coke bed (i.e., coke drum outage) at the end of the coking cycle (feet) from compan y records or engineering estimates . D = Diameter of delayed coking unit vessel (feet). (2) Determine the typical mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to venting to the atmosphere using Equation Y - 18b of this section. 

##   2 coke water water water particle M π D M ρ H 4 ρ

 

         ( Eq. Y - 18b)Page 24 of 54

Where: M water = Mass of water in the delayed coking unit vessel at the end of the cooling cycle

just prior to atmospheric venting (metric ton s /cycle). ρ water = Density

of water at average temperature of the delayed coking unit vessel at the end of the cooling cycle just prior to atmospheric venting (metric tons per cubic feet; mt/ft 3 ). Use the default value of 0.0270 mt/ft 3

. H water = Ty

pical distance from the bottom of the coking unit vessel to the top of the water level at the end of the cooling cycle just prior to atmospheric venting (feet) from compan y records or engineering estimates . M coke = Ty

pical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (metric ton s /cycle) as determined in paragraph (i)( 1) of this section . ρ particle = Particle density of coke (metric tons per cubic feet; mt/ft 3 ). Use the default value of 0.0382 mt/ft 3

. D = Diameter of delayed coking unit vessel (feet). ( 3) Determine the average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere using either Equation Y - 18 c or Y - 18d of this section , as appropriate, based on the measurement s ys tem available. T initial = ( T overhead + T bottom ) /2 (Eq. Y-18c) Where: T initial = Average temperature of the delayed coking unit vessel when the drum is first

vented to the atmosphere (°F). T overhead = Temperature of the delayed coking unit vessel overhead line measured as near

the coking unit vessel as practical just prior to venting to the atmosphere. If the t emperature of the delayed coking unit vessel overhead line is less than 216 °F, use T overhead = 216 °F. T bottom = Temperature of the delayed coking unit vessel near the bottom of the coke bed.

If the temperature at the bottom of the coke bed is less than 21 2 °F, use T bottom = 21 2 °F . T initial = - 0.039 P overhead

2 + 3.13 P overhead +220 (Eq. Y - 18d)Page 25 of 54 Where: T initial = Average temperature of the P overhead = Pressure of the ( 4 ) Determine the typical mass of steam 

###   

##     ConvLoss water p,water coke p,coke initial fin al steam vap 1 f M C M C T T M H          (Eq. Y - 18e) Where: M steam = Mass of steam f ConvL oss = fraction of total heat M water = Mass of water in the C p,water = Heat capacity of M coke = Ty

pical dry mass of coke in C p,coke = Heat capacity of T initial = Average temperature of the T final = Temperature of the delay ed ΔH vap = Heat of vaporization (5) C alculate the CH 4 emissions from decoking

4 s team DCU CH M E mF N 0 .001     (Eq. Y - 18f) Where: CH 4 = Annual methane emissions from the delayed coking un it decoking operations

(metric ton/year). M steam = Mass of steam generated and released per decoking cycle (metric tons/cycle) as

determined in paragraph (i)(3) of this section . EmF DCU = Methane emission factor for delayed coking unit (kilograms CH 4 per metric ton

of steam; kg CH 4 /mt steam) from unit - specific measurement data. If you do not have unit - specific measurement data, u se the default value of 7.9 kg CH 4 /m etric ton steam. N = Cumulative number of decoking cycles (or coke - cutting cycles ) for all delayed coking unit vessels associated with the delayed coking unit during the ye ar. 0.001 = Conversion factor (metric ton/kg). (j) For each process vent not covered in paragraphs (a) through (i) of this section that can reasonabl y be expected to contain greater than 2 percent b y volume CO 2 or greater than 0.5Page 26 of 54

percent b y volume of CH 4 or greater than 0.01 percent b y volume (100 parts per million) of N 2 O, calculate GHG emissions using Equation Y - 19 of this section. You must also use Equation Y - 19 of this section to calculate CH 4 emissions for cataly tic reforming unit depressurization and purge vents when methane is used as the pur ge gas , and CO 2 and/or CH 4 emissions, as applicable, if yo u elected this method as an alternative to the methods in paragraphs (f), (h), or (k) of this section. (Eq. Y - 19) Where: E X = 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. (MF X) 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. MW X = Molecular weight of GHG x (kg/kg - mole ); use 44 for CO 2 or N 2 O and 16 for

CH 4 . MVC = 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). (VT) p = Venting time for the event, (hours). 0.001 = Conversion factor (metric ton/kg). (k) For uncontrolled blowdown sy stems, you must calculate CH 4 emissions either using the methods for process vents in paragraph (j) of this section regardless of the CH 4 concentration or using Equation Y - 20 of this section. Blowdown sy stems where the unconde nsed gas stream isPage 27 of 54

routed to a flare or similar control device are considered to be controlled and are not required to estimate emissions under this paragraph (k). (Eq. Y - 20) Where: CH 4 = Methane emission rate from blowdown sy stems (mt CH 4 /year). Q Ref = Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year). EF BD = Methane emission factor for uncontrolled blown sy stems (scf CH 4 /MMbbl);

default is 137,000. 16 = Molecular weight of CH 4 (kg/kg - mole). MVC = 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). 0.001 = Conversion factor (metric ton/kg). (l) For equipment leaks, calculate CH 4 emissions using the metho d 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 an y of the emission estimation procedures provided in the Protocol for Equipment L eak Emiss ions Estimates (EPA - 453/R - 95 - 017, NTIS PB96 - 175401). (2) Use Equation Y - 21 of this section. (Eq. Y - 21) Where: CH 4 = Annual methane emissions from equipment leaks (metric tons/year). N CD = Number of atmospheric crude oil distillation columns at the facility .Page 28 of 5 4

N PU1 = Cumulative number of cataly tic cracking units, coking units (delayed or fluid), hydrocracking, and full - range distillation columns (including depropanizer and debutanizer distillation columns) at the facility . N PU2 = Cumulative number of hydrotreating/hydrorefining units, catal yt ic reforming

units, and visbreaking units at the facility . N H2 = Total number of h ydrogen plants at the facility. N FGS = Total number of fuel gas sy stems at the facility . (m) For storage tanks, except as provided in paragraph (m)(3) of this section, calculate CH 4 emissions using the applicable methods in paragraphs (m)(1) and (2) of this section. (1) For storage tanks other than those processing unstabilized crude oil, you must either calculate CH 4 emissions from sto rage 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 (incorporate d by

reference, see §98.7) or estimate CH 4 emissions from storage tanks using Equation Y - 22 of this section. (Eq. Y - 22) Where: CH 4 = Annual methane emissions from storage tanks (metric tons/year). 0.1 = Default emission factor for storage tanks (metric ton CH 4 /MMbbl). Q Ref = 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 CH 4 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.Page 29 of 54 (Eq. Y - 23)

Where: CH 4 = Annual me thane emissions from storage tanks (metric tons/year). Q un = 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). MF CH 4 = Average mole fraction of CH 4 in vent gas from the unstabilized crude oil

storage tanks from facility measurements (kg - mole CH 4 /kg - mole gas); use 0.27 as a default if measurement data are not available. 995,000 = Correlation Equation factor (scf gas per MMbbl per psi). 16 = Molecular weight of CH 4 (kg/kg - mole). MVC = 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). 0.001 = Conversion factor (metric ton/kg). (3) You do not need to calcu late CH 4 emissions from storage tanks that meet an y of the following descriptions: (i) Units permanentl y 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 v apor - phase concentration of methane is 0.5 volume percent or more, calculate CH 4 emissions from loadingPage 30 of 54

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. **§98.254 Monitoring and QA/QC requirements.** (a) Fuel fl ow meters, gas composition monitors, and heating value monitors that are associated with sources that use a CEMS to measure CO 2 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 require ments 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. (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 frequencyPage 31 of 54

specified b y 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 compl y 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 Ameri can 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.o rg ), the American Petroleum Institute (API, 1220 LStreet, NW., Washington, DC 20005 - 4070, (202) 682 - 8000, http://www.api.org ), and the North American Energy Standards 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. Alternativel y, the results of chromatographic anal ys is 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 Moni toring Plan for the unit under §98.3(g)(5). (1) Method 18 at 40 CFR part 60, appendix A - 6.Page 32 of 54

(2) ASTM D1945 - 03 Standard Test Method for Analy sis of Natural Gas by Gas Chromatograph y (incorporated b y reference, see §98.7). (3) ASTM D1946 - 90 (Reapproved 2006) Standard Practice for Anal ys is of Reformed Gas b y Gas Chromatography (incorporated b y reference, see §98.7). (4) GPA 2261 - 00 Analy sis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatograph y (incorporated b y reference, see §98.7). (5) UOP539 - 97 R efinery Gas Anal ys is by Gas Chromatograph y (incorporated by reference, see §98.7). (6) ASTM D2503 - 92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons b y Thermoelectric Measurement of Vapor Pressure (inco rporated b y reference, see §98.7). (e) Determine flare gas higher heating value using any of the following methods. Alternativel y, 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 L iquid 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 b y reference, see §98.7).Page 33 of 54

(3) ASTM D1826 - 94 (Reapproved 2003) Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range b y Continuous Recording Calorimeter (incorporated b y reference, see §98.7). (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 b y 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 s ys tem 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 CO 2 /CO/O 2 composition 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 63.1572(c) or according to the manufacturer's specifications and requirements.Page 34 of 54

(h) Determine the mass of petroleum coke as required b y 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, NI ST Handbook 44 (2009) (incorporated by reference, see §98.7). Calibrate the measurement device according to the procedures specified by NI ST handbook 44 (incorporated by r eference, see §98.7) or the procedures specified by the manufacturer. Recalibrate either bienniall y or at the minimum frequency specified b y the manufacturer. (i) Determine the carbon content of petroleum coke as required by Equation Y - 13 of this subpart u sing an y one of the following methods. Calibrate the measurement device according to procedures specified b y the method or procedures specified b y the measurement device manufacturer. (1) ASTM D3176 - 89 (Reapproved 2002) Standard Practice for Ultimate Analy sis 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 in Petroleum Products and Lubricants (incorporated b y reference, see §98 .7). (3) ASTM D5373 - 08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in L aboratory Samples of Coal (incorporated by reference, see §98.7). (j) Determine the quantity of petroleum process streams using company record s. These quantities include the quantity of coke produced per cycle, 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 .Page 35 of 54

(k) Determine temperature or pressure of delayed coking unit vessel using process instrumentation operated, maintained, and calibrated according to the manufacturer's instructions . ( l ) 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 rec orded, 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 he ating 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 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. I f the “after” value is not obtained by

the end of the reporting ye ar, you may use the “before” value for the miss ing data substitution. I f, 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.Page 36 of 54

(c) For missing CO 2 , CO, O 2 , CH 4 , or N 2 O 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 h ydrogen plants, use the missing data procedures in subpart P of this part. **§98.256 Data reporting requirements.** In addition to the reporting requirements o f §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 h ydro gen 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 (st eam assisted, air - assisted). (3) A description of the flare service (general facility flare, unit flare, emergency onl y or back - up flare) and an indication of whether or not the flare is serviced b y a flare gas recovery sy stem . (4) The calculated CO 2 , CH 4 , and N 2 O annual emissions for each flare, expressed in metric tons of each pollutant emitted. (5) A description of the method used to calculate the CO 2 emissions for each flare (e.g., reference section and equation number).Page 37 of 54

(6) If you use Equation Y - 1a of §98.253, an indication of whether dail y or weekl y measurement periods are used, annual average carbon content of the flare gas (in kg carbon per kg flare gas) , and, either the annual volume of flare gas combusted (in scf/year) and the annual average molec ular weight (in kg/kg - mole) , or, the annual mass of flare gas combusted (in kg/yr) . (7) If you use Equation Y - 1b of §98.253, an indication of whether dail y or weekl y measurement periods are used, the annual volume of flare gas combusted (in scf/year), the annual average CO 2 concentration (volume or mole percent), the number of carbon containing compounds other than CO 2 in the flare gas stream, and for each of the carbon containing compounds other than CO 2 in the flare gas stream: (i) The annual average concentration of the compound (volume or mole percent). (ii) [Reserved] (8) If you use Equation Y - 2 of this subpart, an indication of whether dail y or weekl y 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 §98.253, the number of SSM events exceeding 500,0 00 scf/day . (10) The basis for the value of the fraction of carbon in the flare gas contributed by methane used in Equation Y - 4 of §98.253. (f) For catal yt ic cracking units, traditional fluid coking units, and cataly tic reforming units, owners and operator s shall report:Page 38 of 54

(1) The unit ID number (if applicable). (2) A description of the type of unit (fluid catal yt ic cracking unit, thermal cataly tic cracking unit, traditional fluid coking unit, or cataly tic reforming unit). (3) Maximum rated throughput of the unit, in bbl/stream day . (4) The calculated CO 2 , CH 4 , and N 2 O annual emissions for each unit, expressed in metric tons of each pollutant emitted. (5) A description of the method used to calculate the CO 2 emissions for each unit (e.g., reference section and equation number). (6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology , the CO 2 annual emissions as measured b y the CEMS (unadjusted to remove CO 2 combustion emissions associated with additional unit s, if present) and the process CO 2 emissions as calculated according to §98.253(c)(1)(ii). Report the CO 2 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 §98.253, the annual average exhaust gas flow rate, %CO 2 , and %CO. (8) If you use Equation Y - 7a of this subpart, the annual average flow rate of inlet air and oxygen - enriched air, %O 2 , %O oxy , %C O 2 , and %CO. (9) If you use Equation Y - 7b of this subpart, the annual average flow rate of inlet air and oxygen - enriched air, %N 2,oxy , and %N 2,exhaust. (10) If you use Equation Y - 8 of §98.253, the basis for the value of the average carbon content of coke.Page 39 of 54

(11) Indicate whether yo u use a measured value, a unit - specific emission factor, or a default for CH 4 emissions. If you use a unit - specific emission factor for CH 4 , report the basis for the factor. (12) Indicate whether yo u use a measured value, a unit - spe cific emission factor, or a default emission factor for N 2 O emissions. I f you use a unit - specific emission factor for N 2 O, report the basis for the factor. (13) If you use Equation Y - 11 of §98.253, the number of regeneration cycles or measurement periods d

uring the reporting year and the average coke burn - off quantity per cycle or measurement period. (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 . (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 calcul ated at the flexicoking unit, also report the calculated annual CO 2 , CH 4 , and N 2 O 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 th is 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).Page 40 of 54

(2) For each on - site sulfur recovery plant, the maximum rate d throughput (metric tons sulfur produced/stream day), a description of the ty pe of sulfur recovery

plant, and an indication of the method used to calculate CO 2 annual emissions for the sulfur recovery plant ( e.g., CO 2 CEMS, Equation Y - 12, or process vent method in §98.253(j)). (3) The calculated CO 2 annual emissions for each on - site sulfur recovery plant, expressed in metric tons. The calculated annual CO 2 emissions from sour gas sent off - site for sulfur recovery , expressed in metric tons. (4) [Reserved] (5) If you recycle tail gas to the front of the 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 CO 2 emissions in the tail gas was used in Equation Y - 12 of §98.253. If so, then report: (i) Indicate whether you used the default (95 percent) or a unit specific correction, and if a unit - specific correction was used, report the value of the correction and the approach used. (ii) If the following data are not used to calculate the recycling correction factor, report the information specified in paragraphs (h)(5)(ii)(A) through (B) of this section. (A) The annual volume of recycled tail gas (in scf/year) . (B) The annual average mol e fraction of carbon in the tail gas (in kg - mole C/kg - mole gas). (6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology , the CO 2 annual emissions as measured b y the CEMS and the annual process CO 2 emiss ions calculated according to §98.253(f)(1). Report the CO 2 annual emissionsPage 41 of 54

associated with fuel combustion in accordance with subpart C of this part (General Stationary Fuel Combustion Sources). (7) If you use the process vent method in §98.253(j) for a n on - 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, i n metric tons coke calcined/stream day . (3) The calculated CO 2 , CH 4 , and N 2 O annual emissions for each unit, expressed in metric tons of each pollutant emitted. (4) A description of the method used to calculate the CO 2 emissions for each unit (e.g., reference section and equation number). (5) If you use Equation Y - 13 of §98.253, 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 CO 2 annual emissions as measured b y the CEMS and the annual process CO 2 emissions calculated according to §98.253(g)(1). (7) In dicate whether you use a measured value, a unit - specific emission factor or a default emission factor for CH 4 emissions. If you use a unit - specific emission factor for CH 4 , report the basis for the factor. (8) Indicate whether you use a measured value, a unit - specific emission factor, or a default emission factor for N 2 O emissions. I f you use a unit - specific emission factor for N 2 O, report the basis for the factor.Page 42 of 54

(j) For asphalt blowing operations, the owner or operator shall report: (1) The unit ID numbe r (if applicable). (2) [Reserved] (3) The type of control device used to reduce methane (and other organic) emissions from the unit. (4) The calculated annual CO 2 and CH 4 emissions for each unit, expressed in metric tons of each pollutant emitted. (5) If you use Equation Y - 14 of §98.253, the basis for the CO 2 emission factor used. (6) If you use Equation Y - 15 of §98.253, the basis for the CH 4 emission factor used. (7) If you use Equation Y - 16a of §98.253, the basis for the carbon emission factor used. (8) I f you use Equation Y - 16b of §98.253, the basis for the CO 2 emission factor used and the basis for the carbon emission factor used. (9) If you use Equation Y - 17 of §98.253, the basis for the CH 4 emission factor used. (10) If you use Equation Y - 19 of this subpart, the relevant information required under paragraph (l)(5) of this section. (k) For each delayed coking unit , the owner or operator shall report: (1) The unit ID number (if applicable). (2) Maximum rated throughput of the unit, in bbl/stream day . ( 3) Annual quantity of coke produced in the unit during the reporting ye ar, in metric tons. (4) The calculated annual CH 4 emissions (in metric tons of CH 4 ) for the delayed coking unit . ( 5 ) The total number of delayed coking vessels (or coke drums) associated with the delayed coking unit .Page 43 of 54

( 6 ) The basis for the ty

pical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (mass measurements from company records or calculated using Equatio n Y 18a) . (7) An indication of the method used to estimate the average temperature of the coke bed, T initial (overhead temperature and Equation Y - 18c or pressure correlation and Equation Y - 18d). (8) An indication of whether a unit - specific methane emissions factor or the default methane emission factor was used for the delayed coking unit. (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. (3) The type of control device used to reduce methane (and other organic) emissions from the unit, if applicable. (4) The calculated annual CO 2 , CH 4 , and N2 O 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, and for intermittent vents, the number of venting events and the cumulative venting time. (m) For uncontrolled blowdown sy stems, the owner or operator shall report: (1) An i ndication 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 an y uncontrolled blowdown sy stems.Page 44 of 54

(2) The cumulative annual CH 4 emissions (in metric tons of CH 4 ) for uncontrolled blowdown sy stems. (3) For uncontrolled blowdown sy stems reporting under §98.253(k), the basis for the value of the methane emission factor used for uncontrolled blowdown sy stems. (4) For uncontrolled blowdown sy stems 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 CH 4 emissions (in metric tons of each pollutant emitted) for all equipment leak sources. (2) The method us ed to calculate the reported equipment leak emissions. (3) The number of each ty pe 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 CH 4 emissions (in metric tons of CH 4 ) 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 emission s for storage tanks other than those processing unstabilized crude ( i.e., either AP 42, Section 7.1 (incorporated b y reference, see §98.7), or Equation Y - 22 of this section). (ii) [Reserved] (3) The cumulative CH 4 emissions (in metric tons of CH 4 ) for stor age tanks used to process unstabilized crude oil or a statement that the facility did not receive any unstabilized crude oil during the reporting year.Page 45 of 54

(4) For storage tanks that process unstabilized crude oil: (i) The method used to calculate the reported unstabilized crude oil storage tank emissions. (ii) - (iv) [Reserved] (v) The basis for the mole fraction of CH 4 in vent gas from unstabilized crude oil storage tanks. (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 CH 4 emissions for storage tanks used to process unstabilized crude oil. (5) - (7) [Reserved] (p) For loading operations, the owner or operator shall report: (1) The cumulative annual CH 4 emissions (in metric tons of each pollutant emitted) for loading operations. (2) The types of materials loaded that have an equilibrium vapor- phase concentration of methane of 0.5 volume percent or greater, and the ty pe of vessel (barge, tanker, marine ves sel, etc.) in which each type of 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.Page 46 of 54

**§98.257 Records that must be retained.** In addition to the records required b y §98.3(g), yo u must retain the records specified in paragraphs (a) and (b) of this section. (a) The records of all parameters monitored under §98.255. If you compl y with the combustion methodology in §98.252(a), then you must retain under this subpart the records required fo r the Tier 3 and/or Tier 4 Calculation Methodologies in §98.37 and you must keep records of the annual average flow calculations. (b) Verification software records. You must keep a record of the file generated by the verification software specified in §98. 5(b) for the applicable data specified in paragraphs (b)(1) through ( 7 3 ) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (b)(1) through ( 7 3 ) of this section. (1) Volume of flare gas combusted d uring measurement period (scf) (Equation Y - 1b of §98.253). (2) Mole percent CO 2 concentration in the flare gas stream during the measurement period (mole percent) (Equation Y - 1b). (3) Mole percent concentration of compound “x” in the flare gas stream durin g the measurement period (mole percent) (Equation Y - 1b). (4) Carbon mole number of compound “x” in the flare gas stream during the measurement period (mole carbon atoms per mole compound) (Equation Y - 1b). (5) Molar volume conversion factor (scf per kg - mole ) (Equation Y - 1b). (6) Annual volume of flare gas combusted for each flare during normal operations from compan y records (million (MM) standard cubic feet per ye ar, MMscf/year) (Equation Y - 3 of §98.253).Page 47 of 54

(7) Higher heating value for fuel gas or flare gas for each flare from company records (British thermal units per scf, Btu/scf = MMBtu/MMscf) (Equation Y - 3). (8) Volume of flare gas combusted during indexed start - up, shutdown, or malfunction event from engineering calculations (scf) (Equation Y - 3). (9) Ave rage molecular weight of the flare gas, from the anal ys is results or engineering calculations for the event (kg/kg - mole) (Equation Y - 3). (10) Molar volume conversion factor (scf per kg - mole) (Equation Y - 3). (11) Average carbon content of the flare gas, fro m anal ys is results or engineering calculations for the event (kg C per kg flare gas) (Equation Y - 3). (12) Weight fraction of carbon in the flare gas prior to combustion in each flare that is contributed by

methane from measurement values or engineering cal culations (kg C in methane in flare gas/kg C in flare gas) (Equation Y - 4 of §98.253). (13) Annual throughput of unit from company records for each catal yt ic cracking unit or fluid coking unit (barrels/year) (Equation Y - 8 of §98.253). (14) Coke burn - off fac tor from engineering calculations (default for catal yt ic cracking units = 7.3; default for fluid coking units = 11) (kg coke per barrel of feed) (Equation Y - 8). (15) Carbon content of coke based on measurement or engineering estimate (kg C per kg coke) (Equation Y - 8). (16) Value of unit - specific CH 4 emission factor, including the units of measure, for each catal yt ic cracking unit, traditional fluid coking unit, catal yt ic reforming unit, and coke calcining unit (calculation method in §98.253(c)(4)). (17) Annual activity

data (e.g., input or product rate), including the units of measure, in units of measure consistent with the emission factor, for each catal yt ic cracking unit, traditionalPage 48 of 54

fluid coking unit, cataly

tic reforming unit, and coke calcining unit (calculation method in §98.253(c)(4)). (18) Value of unit - specific N 2 O emission factor, including the units of measure, for each catal yt ic cracking unit, traditional fluid coking unit, catal yt ic reforming unit, and coke calcining unit (calculation method in § 98.253(c)(5)). (19) Annual activity

data (e.g., input or product rate), including the units of measure, in units of measure consistent with the emission factor, for each catal yt ic cracking unit, traditional fluid coking unit, cataly

tic reforming unit, and coke calcining unit (calculation method in §98.253(c)(5)). (20) Carbon content of coke based on measurement or engineering estimate (default = 0.94) (kg C per kg coke) (Equation Y - 11 of §98.253). (21) Volumetric flow rate of sour gas (including sour water stripper gas) feed sent off site for sulfur recovery

in the year (scf/ye ar) (Equation Y - 12 of §98.253). (22) Mole fraction of carbon in the sour gas feed sent off site for sulfur recovery (kg mole C/kg - mole gas) (Equation Y - 12). (23) Molar volume conversio n factor for sour gas sent off site (scf per kg - mole) (Equation Y - 12). (24) Volumetric flow rate of sour gas (including sour water stripper gas) fed to the onsite sulfur recovery

plant (scf/year) (Equation Y - 12). (25) Mole fraction of carbon in the sour ga s fed to the onsite sulfur recovery plant (kg mole C/kg - mole gas) (Equation Y - 12). (26) Molar volume conversion factor for onsite sulfur recovery plant (scf per kg - mole) (Equation Y - 12).Page 49 of 54

(27) Annual mass of green coke fed to the coke calcining unit from facility records (metric tons/year) (Equation Y - 13 of §98.253). (28) Annual mass of marketable petroleum coke produced b y the coke calcining unit from facility records (metric tons/year) (Equation Y - 13). (29) Annual mass of petroleum coke dust removed from the process through the dust collection sy stem of the coke calcining unit from facility records. 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 cok e dust recycled to the process (metric tons/year) (Equation Y 13). (30) Average mass fraction carbon content of green coke from facility measurement data (metric tons C per metric ton green coke) (Equation Y - 13). (31) Average mass fraction carbon content o f marketable petroleum coke produced b y the coke calcining unit from facility measurement data (metric tons C per metric ton petroleum coke (Equation Y - 13). (32) Quantity of asphalt blown for each asphalt blowing unit (million barrels per year (MMbbl/year) ) (Equation Y - 14 of §98.253). (33) Emission factor for CO 2 from uncontrolled asphalt blowing from facility - specific test data for each asphalt blowing unit (metric tons CO 2 /MMbbl asphalt blown) (Equation Y - 14). (34) Emission factor for CH 4 from uncontrolle d asphalt blowing from facility- specific test data for each asphalt blowing unit (metric tons CH 4 /MMbbl asphalt blown) (Equation Y - 15 of §98.253). (35) Quantity of asphalt blown (million barrels/year (MMbbl/year)) (Equation Y - 16a of §98.253).Page 50 of 54

(36) Carbon emission factor from asphalt blowing from facilit y- specific test data (metric tons C/MMbbl asphalt blown) (Equation Y - 16a). (37) Quantity of asphalt blown for each asphalt blowing unit (million barrels per year (MMbbl/year)) (Equation Y - 16b of §98.253). (3 8) Emission factor for CO 2 from uncontrolled asphalt blowing from facility - specific test data for each asphalt blowing unit (metric tons CO 2 /MMbbl asphalt blown) (Equation Y 16b). (39) Carbon emission factor from asphalt blowing from facility- specific test data for each asphalt blowing unit (metric tons C/MMbbl asphalt blown) (Equation Y - 16b). (40) Emission factor for CH 4 from uncontrolled asphalt blowing from facility - specific test data for each asphalt blowing unit (metric tons CH 4 /MMbbl asphalt blown) (E quation Y - 17 of §98.253). (41) Ty pical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (metric ton s /cycle) from compan y records or calculated using Equation Y - 18a (Equations Y - 18a, Y - 18b and Y - 18 e of § 98.253 ) for each delayed coking unit . (42) Internal h eight of delayed coking unit vessel (feet) (Equation Y - 18a) for each delayed co king unit. (43) T ypical distance from the top of the delayed coking unit vessel to the top of the coke bed (i.e., coke drum outage) at the end of the coking cycle (feet) from company records or engineering estimates (Equation Y - 18 a) for each delayed coking unit . ( 4 4 ) Diameter of delayed coking unit vessel (feet) (Equation Y - 18 a and Y - 18b ) for each delayed coking unit .Page 51 of 54

(45) Mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to atmospheric venting (metric ton/cycle) (Equations Y - 18b and Y - 18 e ) for each delayed coking unit. (46) Ty

pical distance from the bottom of the coking unit vessel to the top of the water level at the end of th e cooling cycle just prior to atmospheric venting (feet) from compan y records or engineering estimates (Equation Y - 18b) for each delayed coking unit. (4 7 ) Mass of steam generated and released per decoking cycle (metric tons/cycle) (Equation s Y - 18 e and Y - 18 f of § 98.253 ) for each delayed coking unit . (48) Average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere (°F) (Equations Y - 18c, Y - 18d, and Y - 18e of § 98.253 ) for each delayed coking unit. (49) Temperature of the delayed coking unit vessel overhead line measured as near the coking unit vessel as practical just prior to venting the atmosphere (Equation Y - 18 c ) for each delayed coking unit. (50) P ressure of the delayed coking unit vessel just prior to opening the atmospheric vent (psig) (Equation Y - 18 d ) for each delayed coking unit. (51) Methane emission factor for delayed coking unit (kilograms CH 4 per metric ton of steam; kg CH 4 /mt steam) ( Equation Y - 18f ) for each delayed coking unit . (52) Cumulative number of decoking cycles (or coke - cutting cycles) for all delayed coking unit vessels associated with the delayed coking unit during the year (Equation Y - 18 f ) for each delayed coking unit .Page 52 of 54

( 5 3 ) Average volumetric flow rate of process gas during the event from measurement data, process knowledge, or engineering estimates for each set of coke drums or vessels of the same size (scf per hour) (Equation Y - 19 of §98.253). ( 5 4 ) Mole fract ion of methane in process vent during the event from measurement data, process knowledge, or engineering estimates for each set of coke drums or vessels of the same size (kg - mole CH 4 /kg - mole gas) (Equation Y - 19). ( 5 5 ) Venting time for the event for each set of coke drums or vessels of the same size (hours) (Equation Y - 19). ( 5 6 ) Molar volume conversion factor for each set of coke drums or vessels of the same size (scf per kg - mole) (Equation Y - 19). ( 5 7 ) Quantity of crude oil plus the quantity of interme diate products received from off site that are processed at the facility (MMbbl/year) (Equation Y - 20 of §98.253). ( 5 8 ) Molar volume conversion factor (scf per kg - mole) (Equation Y - 20). ( 59 ) Methane emission factor for uncontrolled blown sy stems (scf CH 4 /MMbbl) (Equation Y - 20). ( 6 0 ) Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year) (Equation Y - 22 of §98.253). ( 6 1 ) Quantity of unstabilized crude oil received at the f acility (MMbbl/year) (Equation Y 23 of §98.253). ( 6 2 ) Pressure differential from the previous storage pressure to atmospheric pressure (psi) (Equation Y - 23). ( 6 3 ) Average mole fraction of CH 4 in vent gas from the unstabilized crude oil storage tanks from facility

measurements (kg - mole CH 4 /kg - mole gas) (Equation Y - 23).Page 53 of 54

( 6 4 ) Molar volume conversion factor (scf per kg - mole) (Equation Y - 23). ( 6 5 ) Specify

whether the calculated or default loading factor L specified in §98.253(n) is entered, for each liqu id loaded to each vessel (methods specified in §98.253(n)). ( 6 6 ) Saturation factor specified in §98.253(n), for each liquid loaded to each vessel (methods specified in §98.253(n)). ( 6 7 ) True vapor pressure of liquid loaded, for each liquid loaded to ea ch vessel (psia) (methods specified in §98.253(n)). ( 6 8 ) Molecular weight of vapors (lb per lb - mole), for each liquid loaded to each vessel (methods specified in §98.253(n)). ( 69 ) Temperature of bulk liquid loaded, for each liquid loaded to each vessel (°R, degrees Rankine) (methods specified in §98.253(n)). ( 7 0 ) Total loading loss (without efficiency correction), for each liquid loaded to each vessel (pounds per 1000 gallons loaded) (methods specified in §98.253(n)). ( 7 1 ) Overall emission control s ys tem reduction efficiency , including the vapor collection sy stem efficiency

and the vapor recovery

or destruction efficiency (enter zero if no emission controls), for each liquid loaded to each vessel (percent) (methods specified §98.253(n)). ( 7 2 ) Vapor phase concentration of methane in liquid loaded, for each liquid loaded to each vessel (percent b y volume) (methods specified in §98.253(n)). ( 7 3 ) Quantity of material loaded, for each liquid loaded to each vessel (thousand gallon per year) (methods spe cified in §98.253(n)). **§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.Page 54 of 54