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)-(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) and an indication of whether or not the flare is serviced by a flare gas recovery system.

(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 in § 98.253, an indication of whether daily or weekly 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 molecular 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 daily or weekly measurement periods are used, the annual volume of flare gas combusted (in scf/year), 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) [Reserved]

(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 § 98.253, the number of SSM events exceeding 500,000 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 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).

(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 § 98.253, the annual average exhaust gas flow rate, %CO2, and %CO.

(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 § 98.253, the basis for the value of the average carbon content of coke.

(11) Indicate whether you use a measured value, a unit-specific emission factor, or a default for CH4 emissions. If you use a unit-specific emission factor for CH4, report the basis for the factor.

(12) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission factor for N2O emissions. If you use a unit-specific emission factor for N2O, report the basis for the factor.

(13) If you use Equation Y-11 of § 98.253, the number of regeneration cycles or measurement periods during 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 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.

(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 CO2 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 mole 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 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).

(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) [Reserved]

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

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

(2) Maximum rated throughput of the unit, in metric tons asphalt/stream day.

(3) The type of control device used to reduce methane (and other organic) emissions from the unit.

(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 § 98.253, the basis for the CO2 emission factor used.

(6) If you use Equation Y-15 of § 98.253, the basis for the CH4 emission factor used.

(7) If you use Equation Y-16a of § 98.253, the basis for the carbon emission factor used.

(8) If you use Equation Y-16b of § 98.253, the basis for the CO2 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 CH4 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 year, in metric tons.

(4) The calculated annual CH4 emissions (in metric tons of CH4) for the delayed coking unit.

(5) The total number of delayed coking vessels (or coke drums) associated with the delayed coking unit.

(6) The basis for the typical 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 equation Y-18a to § 98.253). If you use mass measurements from company records to determine the typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle, you must also report:

(i) Internal height of delayed coking unit vessel (feet) for each delayed coking unit.

(ii) Typical 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 for each delayed coking unit.

(7) An indication of the method used to estimate the average temperature of the coke bed, Tinitial (overhead temperature and Equation Y-18c of this subpart or pressure correlation and Equation Y-18d of this subpart).

(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 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, 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 basis for the value of the methane emission factor used for uncontrolled blowdown systems.

(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 (incorporated by reference, see § 98.7), or Equation Y-22 of this section).

(ii) [Reserved]

(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)-(iv) [Reserved]

(v) The basis for the mole fraction of CH4 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 CH4 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 CH4 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 type of vessel (barge, tanker, marine vessel, 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.

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79164, Dec. 17, 2010; 78 FR 71963, Nov. 29, 2013; 79 FR 63795, Oct. 24, 2014; 81 FR 89263, Dec. 9, 2016; 89 FR 31931, Apr. 25, 2024]