Page 1 of 27

Subpart X—Petrochemical Production

(a) The petrochemical production source category consists 

of all processes that produce acrylonitrile, carbon black, 

ethylene, ethylene dichloride, ethylene oxide, or methanol, 

except as specified in paragraphs (b) through (g) of this 

section. The source category includes processes that produce the 

petrochemical as an intermediate in the on-site production of 

other chemicals as well as processes that produce the 

petrochemical as an end product for sale or shipment off site.

§ 98.240 Definition of the source category.

(b) A process that produces a petrochemical as a byproduct 

is not part of the petrochemical production source category.

(c) A facility that makes methanol, hydrogen, and/or 

ammonia from synthesis gas is part of the petrochemical source 

category if the annual mass of methanol produced exceeds the 

individual annual mass production levels of both hydrogen 

recovered as product and ammonia. The facility is part of 

subpart P of this part (Hydrogen Production) if the annual mass 

of hydrogen recovered as product exceeds the individual annual 

mass production levels of both methanol and ammonia. The 

facility is part of subpart G of this part (Ammonia 

Manufacturing) if the annual mass of ammonia produced exceeds 

the individual annual mass production levels of both hydrogen 

recovered as product and methanol.
Page 2 of 27

(d) A direct chlorination process that is operated 

independently of an oxychlorination process to produce ethylene 

dichloride is not part of the petrochemical production source 

category.

(e) A process that produces bone black is not part of the 

petrochemical source category.

(f) A process that produces a petrochemical from bio-based 

feedstock is not part of the petrochemical production source 

category.

(g) A process that solely distills or recycles waste 

solvent that contains a petrochemical is not part of the 

petrochemical production source category.

You must report GHG emissions under this subpart if your 

facility contains a petrochemical process as specified in 

§98.240, and the facility meets the requirements of either 

§98.2(a)(1) or (2).

§ 98.241 Reporting threshold.

You must report the information in paragraphs (a) through 

(c) of this section:

§ 98.242 GHGs to report.

(a) CO2 CH4, and N2O process emissions from each 

petrochemical process unit. Process emissions include CO2

generated by reaction in the process and by combustion of 

process off-gas in stationary combustion units and flares.
Page 3 of 27

(1) If you comply with §98.243(b) or (d), report under this 

subpart the calculated CO2, CH4, and N2O emissions for each 

stationary combustion source and flare that burns any amount of 

petrochemical process off-gas. If you comply with §98.243(b), 

also report under this subpart the measured CO2

(2) If you comply with §98.243(c), report under this 

subpart the calculated CO

emissions from 

process vents routed to stacks that are not associated with 

stationary combustion units.

2

(b) CO

emissions for each petrochemical 

process unit.

2, CH4, and N2

(1) If you comply with §98.243(b) or (d), report these 

emissions from stationary combustion units that are associated 

with petrochemical process units and burn only supplemental fuel 

under subpart C of this part (General Stationary Fuel Combustion 

Sources) by following the requirements of subpart C.

O combustion emissions from stationary 

combustion units.

(2) If you comply with §98.243(c), report CO2, CH4, and N2O 

combustion emissions under subpart C of this part (General 

Stationary Fuel Combustion Sources) by following the 

requirements of subpart C for all fuels, except emissions from 

burning petrochemical process off-gas in any combustion unit are 

not to be reported under subpart C of this part. only for the 

combustion of supplemental fuel. Determine the applicable Tier 
Page 4 of 27

in subpart C of this part (General Stationary Fuel Combustion 

Sources) based on the maximum rated heat input capacity of the 

stationary combustion source.

(c) CO2 captured. You must report the mass of CO2 captured 

under, subpart PP of this part (Suppliers of Carbon Dioxide (CO2)

by following the requirements of subpart PP.

(a) If you route all process vent emissions and emissions 

from combustion of process off-gas to one or more stacks and use 

CEMS on each stack to measure CO

§ 98.243 Calculating GHG emissions.

2

(b) 

emissions (except flare 

stacks), then you must determine process-based GHG emissions in 

accordance with paragraph (b) of this section. Otherwise, 

determine process-based GHG emissions in accordance with the 

procedures specified in paragraph (c) or (d) of this section.

Continuous emission monitoring system (CEMS)

(1)Determine CO

. Route all 

process vent emissions and emissions from stationary combustion

units that burn any amount of process off-gas to one or more 

stacks and determine GHG emissions as specified in paragraphs 

(b)(1) through (3) of this section.

2

(2)For each stack (except flare stacks) that includes 

emissions from combustion of petrochemical process off-gas, 

emissions from each stack (except flare 

stacks) according to the Tier 4 Calculation Methodology 

requirements in subpart C of this part. 
Page 5 of 27

calculate CH4 and N2

(3) For each flare, calculate CO

0 emissions in accordance with subpart C of 

this part (use the Tier 3 methodologyEquation C-10 and the “fuel 

gas” , emission factors for “Petroleum” in Table C–2 of subpart 

C of this part)., and either the default high heat value for 

fuel gas in Table C–1 of subpart C of this part or a calculated 

HHV, as allowed in Equation C–8 of subpart C of this part). 

2, CH4, and N2

(c) 

O emissions 

using the methodology specified in §98.253(b)(1) through (b)(3).

Mass balance for each petrochemical process unit. 

Calculate the emissions of CO2

(1) For each gaseous and liquid feedstock and product, 

measure the volume or mass used or produced each calendar month 

with a flow meter by following the procedures specified in 

§98.244(b)(2). Alternatively, for liquids, you may calculate the 

volume used or collected in each month based on measurements of 

the liquid level in a storage tank at least once per month (and 

just prior to each change in direction of the level of the 

liquid) following the procedures specified in §98.244(b)(3). 

Fuels used for combustion purposes are not considered to be 

feedstocks.

from each process unit, for each 

calendar month as described in paragraphs (c)(1) through (c)(5) 

of this section.
Page 6 of 27

(2) For each solid feedstock and product, measure the mass 

used or produced each calendar month by following the procedures 

specified in §98.244(b)(1).

(3) Collect a sample of each feedstock and product at least 

once per month and determine the carbon content of each sample 

according to the procedures of §98.244(b)(4). If multiple valid 

carbon content measurements are made during the monthly 

measurement period, average them arithmetically. However, if a 

particular liquid or solid feedstock is delivered in lots, and 

if multiple deliveries of the same feedstock are received from 

the same supply source in a given calendar month, only one 

representative sample is required. Alternatively, you may use 

the results of analyses conducted by a fuel or feedstock 

supplier, or product customer, provided the sampling and 

analysis is conducted at least once per month using any of the 

procedures specified in §98.244(b)(4).

(4) If you determine that the monthly average concentration 

of a specific compound in a feedstock or product is greater than 

99.5 percent by volume (or mass for liquids and solids), then as 

an alternative to the sampling and analysis specified in

paragraph (c)(3) of this section, you may determine carbon 

content in accordance with paragraphs (c)(4)(i) through (iii) of 

this section.
Page 7 of 27

(i)Ccalculate the carbon content assuming 100 percent of 

that feedstock or product is the specific compound. during 

periods of normal operation. You must m

(ii)Maintain records of any determination made in 

accordance with this paragraph (c)(4) along with all supporting 

data, calculations, and other information. This alternative may 

not be used for products during periods of operation when offspecification product is produced. You must 

(iii)Rreevaluate determinations made under this paragraph 

(c)(4) after any process change that affects the feedstock or 

product composition. You must kKeep records of the process 

change and the corresponding composition determinations. If the 

feedstock or product composition changes so that the average 

monthly concentration falls below 99.5 percent, you are no 

longer permitted to use this alternative method.

(5) Calculate the CO2

(i) 

mass emissions for each petrochemical 

process unit using Equations X–1 through X–4 of this section.

Gaseous feedstocks and products. Use Equation X–1 of 

this section to calculate the net annual carbon input or output 

from gaseous feedstocks and products. Note that the result will 

be a negative value if there are no gaseous feedstocks in the 

process but there are gaseous products.
Page 8 of 27

Where:

Cg = Annual net contribution to calculated 

emissions from carbon (C) in gaseous 

materials, including streams containing CO2

(F

recovered for sale or use in another 

process(kilograms/year, kg/yr).

gf)i,n = Volume or mass of gaseous feedstock i 

introduced in month “n” (standard cubic feet, 

scf or kg). If you measure mass, the term 

(MWf)i

(CC

/MVC is replaced with “1”. 

gf)i,n

(MW

= Average carbon content of the gaseous 

feedstock i for month “n” (kg C per kg of 

feedstock).

f)i,n

MVC = Molar volume conversion factor (849.5 scf per 

kg-mole at 68 °F and 14.7 pounds per square 

inch absolute or 836.6 scf/kg-mole at 60 °F 

and 14.7 pounds per square inch absolute).

= Molecular weight of gaseous feedstock i in 

month “n”(kg/kg-mole).

(Pgp)i,n = Volume or mass of gaseous product i produced 

in month “n” (scf or kg). If you measure mass, 

the term (MWp)i

(CC

/MVC is replaced with “1”.

gp)i,n = Average carbon content of gaseous product i, 

including streams containing CO2

(MW

recovered for 

sale or use in another process, for month “n” 

(kg C per kg of product).

p)Ii =

j = Number of feedstocks.

Molecular weight of gaseous product i in month 

“n” (kg/kg-mole).

k = Number of products.

(ii) Liquid feedstocks and products. Use Equation X–2 of 

this section to calculate the net carbon input or output from 

liquid feedstocks and products. Note that the result will be a 

negative value if there are no liquid feedstocks in the process 

but there are liquid products.
Page 9 of 27

Where:

Cl =

(F

Annual net contribution to calculated 

emissions from carbon in liquid materials, 

including liquid organic wastes (kg/yr).

lf)i,n =

(CC

Volume or mass of liquid feedstock i 

introduced in month “n” (gallons or kg).

lf)i,n =

(P

Average carbon content of liquid feedstock i 

for month “n” (kg C per gallon or kg of 

feedstock).

lp)i,n =

(CC

Volume or mass of liquid product i produced in 

month “n” (gallons or kg).

lp)i,n

j = Number of feedstocks.

= Average carbon content of liquid product i, 

including organic liquid wastes, for month “n” 

(kg C per gallon or kg of product).

k = Number of products.

(iii) Solid feedstocks and products. Use Equation X–3 of 

this section to calculate the net annual carbon input or output 

from solid feedstocks and products. Note that the result will be 

a negative value if there are no solid feedstocks in the process 

but there are solid products.

Where:

Cs

(F

= Annual net contribution to calculated 

emissions from carbon in solid materials 

(kg/yr).

sf)i,n = Mass of solid feedstock i introduced in month 

“n” (kg).
Page 10 of 27

(CCsf)i,n

(P

= Average carbon content of solid feedstock i 

for month “n” (kg C per kg of feedstock).

sp)i,n

(CC

= Mass of solid product i produced in month “n” 

(kg).

sp)i,n

j = Number of feedstocks.

= Average carbon content of solid product i in 

month “n” (kg C per kg of product).

k = Number of products.

(iv) Annual emissions. Use the results from Equations X–1 

through X–3 of this section, as applicable, in Equation X–4 of 

this section to calculate annual CO2 emissions.

Where:

CO2 = Annual CO2

0.001 = Conversion factor from kg to metric tons.

mass emissions from process 

operations and process off-gas combustion 

(metric tons/year).

44 = Molecular weight of CO2

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

(kg/kg-mole).

(d) Optional combustion methodology for ethylene production 

processes

(1) Except as specified in paragraphs (d)(2) and (d)(5) of 

this section, calculate CO

. For each ethylene production process, calculate GHG 

emissions from combustion units that burn fuel that contains any 

off-gas from the ethylene process as specified in paragraphs 

(d)(1) through (d)(5) of this section.

2 emissions using the Tier 3 or Tier 4 

methodology in subpart C of this part.
Page 11 of 27

(2) You may use either Equation C–1 or Equation C–2a in 

subpart C of this part to calculate CO2

(i) The annual average flow rate of fuel gas (that contains 

ethylene process off-gas) 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 a flow meter is not 

installed at any point in the line supplying fuel gas or an 

upstream common pipe. Calculate the annual average flow rate 

using company records assuming total flow is evenly distributed 

over 525,600 minutes per year.

emissions from combustion 

of any ethylene process off-gas streams that meet either of the 

conditions in paragraphs (d)(2)(i) or (d)(2)(ii) of this section 

(for any default values in the calculation, use the defaults for 

fuel gas in Table C–1 of subpart C of this part). Follow the 

otherwise applicable procedures in subpart C to calculate 

emissions from combustion of all other fuels in the combustion 

unit.

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

capacity of less than 30 mmBtu/hr, and a flow meter is not 

installed at any point in the line supplying fuel gas (that 

contains ethylene process off-gas) or an upstream common pipe.

(3) Except as specified in paragraph (d)(5) of this 

section, calculate CH4 and N2O emissions using the applicable 
Page 12 of 27

procedures in §98.33(c) for the same tier methodology that you 

used for calculating CO2

(i) For all gaseous fuels that contain ethylene process 

off-gas, use the emission factors for “Fuel Gas” “Petroleum” in 

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

Combustion Sources).

emissions.

(ii) For Tier 3, use either the default high heat value for 

fuel gas in Table C–1 of subpart C of this part or a calculated 

HHV, as allowed in Equation C–8 of subpart C of this part.

(4) You are not required to use the same Tier for each 

stationary combustion unit that burns ethylene process off-gas.

(5) For each flare, calculate CO2, CH4, and N2O emissions 

using the methodology specified in §§98.253(b)(1) through 

(b)(3).

(a) If you use CEMS to determine emissions from process 

vents, you must comply with the procedures specified in 

§98.34(c).

§ 98.244 Monitoring and QA/QC requirements.

(b) If you use the mass balance methodology in §98.243(c), 

use the procedures specified in paragraphs (b)(1) through (b)(4) 

of this section to determine feedstock and product flows and 

carbon contents.

(1) Operate, maintain, and calibrate belt scales or other 

weighing devices as described in Specifications, Tolerances, and 
Page 13 of 27

Other Technical Requirements for Weighing and Measuring Devices 

NIST Handbook 44 (2009) (incorporated by reference, see §98.7), 

or follow procedures specified by the measurement device 

manufacturer. You must recalibrate each weighing device 

according to one of the following frequencies. You may 

recalibrate either at the minimum frequency specified by the 

manufacturer or biennially (i.e.

(2) Operate and maintain all flow meters used for gas and 

liquid feedstocks and products according to the manufacturer's 

recommended procedures. You must calibrate each of these flow 

meters as specified in paragraphs (b)(2)(i) and (b)(2)(ii) of 

this section:

, once every two years).

(i) You may use either the calibration methods specified by 

the flow meter manufacturer or an industry consensus standard 

method. Each flow meter must meet the applicable accuracy 

specification in §98.3(i), except as otherwise specified in 

§§98.3(i)(4) through (i)(6).

(ii) You must recalibrate each 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.

(3) You must perform tank level measurements (if used to 

determine feedstock or product flows) according to one of the 
Page 14 of 27

following methods. You may use any standard method published by 

a consensus-based standards organization or you may use an 

industry standard practice. Consensus-based standards 

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

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

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

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

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

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

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

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

American Society of Mechanical Engineers (ASME, Three Park 

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

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

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

http://www.api.org,) and the North American Energy Standards 

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

(713) 356–0060, http://www.api.org

(4) Beginning January 1, 2010, use any applicable methods 

specified in paragraphs (b)(4)(i) through (b)(4)(xiv) of this 

section to determine the carbon content or composition of 

feedstocks and products and the average molecular weight of 

gaseous feedstocks and products. Calibrate instruments in 

accordance with paragraphs (b)(4)(i) through (b)(4)(xvi), as 

).
Page 15 of 27

applicable. For coal used as a feedstock, the samples for carbon 

content determinations shall be taken at a location that is 

representative of the coal feedstock used during the 

corresponding monthly period. For carbon black products, samples 

shall be taken of each grade or type of product produced during 

the monthly period. Samples of coal feedstock or carbon black 

product for carbon content determinations may be either grab 

samples collected and analyzed monthly or a composite of samples 

collected more frequently and analyzed monthly. Analyses 

conducted in accordance with methods specified in paragraphs 

(b)(4)(i) through (b)(4)(xv) of this section may be performed by 

the owner or operator, by an independent laboratory, or by the 

supplier of a feedstock, or by a product customer.

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

Natural Gas by Gas Chromatography (incorporated by reference, 

see

(ii) ASTM D6060–96 (Reapproved 2001) Standard Practice for 

Sampling of Process Vents With a Portable Gas Chromatograph 

(incorporated by reference, 

§98.7).

see

(iii) ASTM D2505–88(Reapproved 2004)e1 Standard Test Method 

for Ethylene, Other Hydrocarbons, and Carbon Dioxide in HighPurity Ethylene by Gas Chromatography (incorporated by 

reference, 

§98.7).

see §98.7).
Page 16 of 27

(iv) ASTM UOP539–97 Refinery Gas Analysis by Gas 

Chromatography (incorporated by reference, see

(v) ASTM D3176–89 (Reapproved 2002) Standard Practice 

Method for Ultimate Analysis of Coal and Coke (incorporated by 

reference, 

§98.7).

see

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

for Instrumental Determination of Carbon, Hydrogen, and Nitrogen 

in Petroleum Products and Lubricants (incorporated by reference, 

§98.7).

see

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

Determination of Carbon, Hydrogen, and Nitrogen in Laboratory 

Samples of Coal (incorporated by reference, 

§98.7).

see

(viii) Method 8015C, Method 8021B, Method 8031, or Method 

9060A (all incorporated by reference, 

§98.7).

see

(x) Performance Specification 9 in 40 CFR part 60, appendix 

B for continuous online gas analyzers. The 7-day calibration 

error test period must be completed prior to the effective date 

of the rule.

§98.7).

(xi) ASTM D2593–93 (Reapproved 2009) Standard Test Method 

for Butadiene Purity and Hydrocarbon Impurities by Gas 

Chromatography (incorporated by reference, see

(xii) ASTM D7633–10 Standard Test Method for Carbon Black—

Carbon Content (incorporated by reference, 

§98.7).

see §98.7).
Page 17 of 27

(xiii) The results of chromatographic analysis of a 

feedstock or product, provided that the gas chromatograph is 

operated, maintained, and calibrated according to the 

manufacturer's instructions.

(xiv) The carbon content results of mass spectrometer 

analysis of a feedstock or product, provided that the mass 

spectrometer is operated, maintained, and calibrated according 

to the manufacturer's instructions.

(xv) Beginning on January 1, 2010, the methods specified in 

paragraphs (b)(4)(xv)(A) and (B) of this section may be used as 

alternatives for the methods specified in paragraphs (b)(4)(i) 

through (b)(4)(xiv) of this section.

(A) An industry standard practice or a method published by 

a consensus-based standards organization if such a method exists

for carbon black feedstock oils and carbon black products.

Consensus-based standards organizations include, but are not 

limited to, the following: ASTM International (100 Barr Harbor 

Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-

B2959, (800) 262-1373, http://www.astm.org), the American 

National Standards Institute (ANSI, 1819 L Street, NW., 6th 

floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org

), the American Gas Association (AGA, 400 North Capitol Street, 

NW., 4th Floor, Washington, DC 20001, (202) 824-7000, 
Page 18 of 27

http://www.aga.org ), the American Society of Mechanical 

Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, 

(800) 843-2763, http://www.asme.org ), the American Petroleum 

Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, 

(202) 682-8000, http://www.api.org ), and the North American 

Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, 

Houston, TX 77002, (713) 356-0060, http://www.naesb.org). The 

method(s) used shall be documented in the Mmonitoring Pplan 

required under § 98.3(g)(5).

(B) Modifications of existing analytical methods or other 

methods that are applicable to your process provided that the 

methods listed in paragraphs (b)(4)(i) through (b)(4)(xiv) of 

this section are not appropriate because the relevant compounds 

cannot be detected, the quality control requirements are not 

technically feasible, or use of the method would be unsafe.

(c) If you comply with §98.243(b) or (d), conduct 

monitoring and QA/QC for flares in accordance with §98.254.

For missing feedstock andflow rates, product flow rates, 

and carbon contents, use the same procedures as for missing 

fuel usage as specified in §98.35(b)(2). For missing feedstock 

and product flow rates and carbon contents and missing molecular 

§ 98.245 Procedures for estimating missing data.
Page 19 of 27

weights for gaseous feedstocks and products, use the same 

procedures as for missing carbon contents and missing molecular 

weights for fuels as specified in §98.35(b)(1). For missing 

flare data, follow the procedures in §98.255(b) and (c). 

In addition to the information required by §98.3(c), each 

annual report must contain the information specified in 

paragraphs (a), (b), or (c) of this section, as appropriate for 

each process unit.

§ 98.246 Data reporting requirements.

(a) If you use the mass balance methodology in §98.243(c), 

you must report the information specified in paragraphs (a)(1) 

through (a)(11) of this section for each type of petrochemical 

produced, reported by process unit.

(1) The petrochemical process unit ID number or other 

appropriate descriptor.

(2) The type of petrochemical produced, names of other 

products, and names of carbon-containing feedstocks.

(3) Annual CO2

(4) Each of the monthly volume, mass, and carbon content 

values used in Equations X–1 through X–3 of this subpart (

emissions calculated using Equation X–4 of 

this subpart.

i.e., 

the directly measured values, substitute values, or the 

calculated values based on other measured data such as tank 

levels or gas composition) and the molecular weights for gaseous 
Page 20 of 27

feedstocks and products used in Equation X–1 of this subpart, 

and the temperature (in °F) at which the gaseous feedstock and 

product volumes used in Equation X–1 of this subpart were 

determined. Indicate whether you used the alternative to 

sampling and analysis specified in §98.243(c)(4).

(5) Annual quantity of each type of petrochemical produced 

from each process unit (metric tons).

(6) For each feedstock and product, provide the information 

specified in paragraphs (a)(6)(i) through (a)(6)(iii) of this 

section.

(i) Name of each method listed in §98.244 used to determine 

carbon content or molecular weight in accordance with 

98.244(b)(4);

(ii)Description of each type of device (e.g., flow meter, 

weighing device) used to determine flow or mass in accordance 

98.244(b)(1) through (3).

(iii)Identification of each method (i.e., method number, 

title, or other description) used to determine flow or mass in 

accordance with 98.244(b)(1) through (3). a measured parameter 

(or description of manufacturer's recommended method).

(7) [Reserved]

(8) Identification of each combustion unit that burned both 

process off-gas and supplemental fuel, including combustion 

units that are not part of the petrochemical process unit.
Page 21 of 27

(9) If you comply with the alternative to sampling and 

analysis specified in §98.243(c)(4), the number of days amount 

of time during which off-specification product was produced, the 

volume or mass of off-specification product produced, and if 

applicable, the date of any process change that reduced the 

composition to less than 99.5 percent.

(10) You may elect to report the flow and carbon content of 

wastewater, and you may elect to report the annual mass of 

carbon released in fugitive emissions and in process vents that 

are not controlled with a combustion device. These values may be 

estimated based on engineering analyses. These values are not to 

be used in the mass balance calculation.

(11) If you determine carbon content or composition of a 

feedstock or product using a method under §98.244(b)(4)(xv)(B), 

report the information listed in paragraphs (a)(11)(i) through 

(a)(11)(iviii) of this section. Include the information in 

paragraph (a)(11)(i) of this section in each annual report. 

Include the information in paragraphs (a)(11)(ii) and 

(a)(11)(iii) of this section only in the first applicable annual 

report, and provide any changes to this information in 

subsequent annual reports.

(i) Name or title of the analytical method.

(ii) A copy of the method. If the method is a modification 

of a method listed in §§98.244(b)(4)(i) through (xiv), you may 
Page 22 of 27

provide a copy of only the sections that differ from the listed 

method.

(iii) An explanation of why an alternative to the methods 

listed in §§98.244(b)(4)(i) through (xii) is needed.

(b) If you measure emissions in accordance with §98.243(b), 

then you must report the information listed in paragraphs (b)(1) 

through (b)(8) of this section.

(1) The petrochemical process unit ID or other appropriate 

descriptor, and the type of petrochemical produced.

(2) For CEMS used on stacks that include emissions fromfor

stationary combustion units that burn any amount of off-gas from 

the petrochemical process, report the relevant information 

required under §98.36(c)(2) and (e)(2)(vi) for the Tier 4 

calculation methodology. Sections §98.36(bc)(92)( iii) and 

(c)(2)(ix) dodoes not apply for the purposes of this subpart.

(3) For CEMS used on stacks that do not include emissions 

from are not used for stationary combustion units, report the 

information required under §98.36(b)(6), (b)(7), and 

§98.36(e)(2)(vi).

(4) The CO2 emissions from each stack and the combined CO2

emissions from all stacks (except flare stacks) that handle 

process vent emissions and emissions from stationary combustion 

units that burn process off-gas for the petrochemical process 

unit. For each stationary combustion unit (or group of 
Page 23 of 27

combustion units monitored with a single CO2 CEMS monitoring 

location that meets the conditions in paragraph (b)(2) or (3) of 

this section, ) that burns petrochemical process off-gas, 

provide an estimate based on engineering judgment of the 

fraction of the total CO2

(5) For stationary combustion units that burn process offgas from the petrochemical process unit, report the information 

related to CH

emissions that is attributable to 

combustion of off-gas from the petrochemical process unit.

4 and N2

(i) The each CEMS monitoring location theat meets the 

conditions in paragraph (b)(2) of this section, report the CH

O emissions as specified in paragraphs 

(b)(5)(i) through (b)(5)(iv) of this section.

4

and N2O emissions from each stack that is monitored with a CO2

CEMS, expressed in metric tons of each gas and in metric tons of 

CO2 e. For each CEMS monitoring location,stack provide an 

estimate based on engineering judgment of the fraction of the 

total CH4 and N2

(i) [Reserved]

O emissions that is attributable to combustion of 

off-gas from the petrochemical process unit.

(ii)[Reserved] The combined CH4 and N2O emissions from all 

stationary combustion units, expressed in metric tons of each 

gas and in metric tons of CO2

(iii) [Reserved]The quantity of each type of fuel used in 

Equation C–8 in §98.33(c) for each stationary combustion unit or 

e.
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group of units (as applicable) during the reporting year, 

expressed in short tons for solid fuels, gallons for liquid 

fuels, and scf for gaseous fuels.

(iv)[Reserved] The HHV (either default or annual average 

from measured data) used in Equation C–8 in §98.33(c) for each 

stationary combustion unit or group of combustion units (as 

applicable).

(6) [Reserved] ID or other appropriate descriptor of each 

stationary combustion unit that burns process off-gas.

(7) Information listed in §98.256(e) of subpart Y of this 

part for each flare that burns process off-gas.

(8) Annual quantity of each type of petrochemical produced 

from each process unit (metric tons).

(c) If you comply with the combustion methodology specified 

in §98.243(d), you must report under this subpart the 

information listed in paragraphs (c)(1) through (c)(5) of this 

section.

(1) The ethylene process unit ID or other appropriate 

descriptor.

(2) For each stationary combustion unit that burns ethylene 

process off-gas (or group of stationary sources with a common 

pipe), except flares, the relevant information listed in §98.36 

for the applicable Tier methodology. For each stationary 

combustion unit or group of units (as applicable) that burns 
Page 25 of 27

ethylene process off-gas, provide an estimate based on 

engineering judgment of the fraction of the total emissions that 

is attributable to combustion of off-gas from the ethylene 

process unit.

(3) Information listed in §98.256(e) of subpart Y of this 

part for each flare that burns ethylene process off-gas.

(4) Name and annual quantity of each feedstock (metric 

tons).

(5) Annual quantity of ethylene produced from each process 

unit (metric tons).

In addition to the recordkeeping requirements in §98.3(g), 

you must retain the records specified in paragraphs (a) through 

(c) of this section, as applicable.

§ 98.247 Records that must be retained.

(a) If you comply with the CEMS measurement methodology in 

§98.243(b), then you must retain under this subpart the records 

required for the Tier 4 Calculation Methodology in §98.37, 

records of the procedures used to develop estimates of the 

fraction of total emissions attributable to combustion of 

petrochemical process off-gas as required in §98.246(b), and 

records of any annual average HHV calculations.

(b) If you comply with the mass balance methodology in 

§98.243(c), then you must retain records of the information 

listed in paragraphs (b)(1) through (b)(34) of this section.
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(1) Results of feedstock or product composition 

determinations conducted in accordance with §98.243(c)(4).

(2) Start and end times and calculated carbon contents for 

time periods when off-specification product is produced, if you 

comply with the alternative methodology in §98.243(c)(4) for 

determining carbon content of feedstock or product.

(3) A part of the monitoring plan required under

§98.3(g)(5), record the estimated accuracy of measurement 

devices and the technical basis for these estimates.

(4) The dates and results (e.g.

(c) If you comply with the combustion methodology in 

§98.243(d), then you must retain under this subpart the records 

required for the applicable Tier Calculation Methodologies in 

§98.37. If you comply with §98.243(d)(2), you must also keep 

records of the annual average flow calculations.

, percent calibration error) 

of the calibrations of each measurement device.

Except as specified in this section, all terms used in this 

subpart have the same meaning given in the Clean Air Act and 

subpart A of this part.

§ 98.248 Definitions.

Product, as used in §98.243, means each of the following 

carbon-containing outputs from a process: the petrochemical, 

recovered byproducts, and liquid organic wastes that are not 
Page 27 of 27

incinerated combusted onsite. Product does not include process 

vent emissions, fugitive emissions, or wastewater.