1

Subpart A—General Provisions 

§98.1 Purpose and Scope.

(a) This part establishes mandatory greenhouse gas 

(GHG) reporting requirements for owners and operators of 

certain facilities that directly emit GHG as well as for 

certain fossil fuel suppliers and industrial GHG suppliers. 

For suppliers, the GHGs reported are the quantity that 

would be emitted from combustion or use of the products 

supplied. 

(b) Owners and operators of facilities and suppliers 

that are subject to this part must follow the requirements 

of subpart A and all applicable subparts of this part. If 

a conflict exists between a provision in subpart A and any 

other applicable subpart, the requirements of the subparts 

B through PP of this part shall take precedence. 

§98.2 Who must report?

(a) The GHG reporting requirements and related 

monitoring, recordkeeping, and reporting requirements of 

this part apply to the owners and operators of any facility 

that is located in the United States and that meets the 

requirements of either paragraph (a)(1), (a)(2), or (a)(3) 

of this section; and any supplier that meets the 

requirements of paragraph (a)(4) of this section: 
2

(1) A facility that contains any source category (as 

defined in subparts C through JJ of this part) that is 

listed in this paragraph (a)(1) in any calendar year 

starting in 2010. For these facilities, the annual GHG 

report must cover all source categories and GHGs for which 

calculation methodologies are provided in subparts C 

through JJ of this part. 

(i) Electricity generation (units that report CO2 

emissions year-round through 40 CFR part 75). 

(ii) Adipic acid production. 

(iii) Aluminum production. 

(iv) Ammonia manufacturing. 

(v) Cement production. 

(vi) HCFC-22 production. 

(vii) HFC-23 destruction processes that are not 

collocated with a HCFC-22 production facility and that 

destroy more than 2.14 metric tons of HFC-23 per year. 

(viii) Lime manufacturing. 

(ix) Nitric acid production. 

(x) Petrochemical production. 

(xi) Petroleum refineries. 

(xii) Phosphoric acid production. 

(xiii) Silicon carbide production. 

(xiv) Soda ash production. 
3

(xv) Titanium dioxide production. 

(xvi) Municipal solid waste landfills that generate 

CH4 in amounts equivalent to 25,000 metric tons CO2e or more 

per year, as determined according to subpart HH of this 

part. 

(xvii) Manure management systems with combined CH4 and 

N2O emissions in amounts equivalent to 25,000 metric tons 

CO2e or more per year, as determined according to subpart JJ 

of this part.

(2) A facility that contains any source category (as 

defined in subparts C through JJ of this part) that is 

listed in this paragraph (a)(2) in any calendar year 

starting in 2010 and that emits 25,000 metric tons CO2e or 

more per year in combined emissions from stationary fuel 

combustion units, miscellaneous uses of carbonate, and all 

source categories that are listed in this paragraph. For 

these facilities, the annual GHG report must cover all 

source categories and GHGs for which calculation 

methodologies are provided in subparts C through JJ of this 

part. 

(i) Ferroalloy Production. 

(ii) Glass Production. 

(iii) Hydrogen Production. 

(iv) Iron and Steel Production. 
4

(v) Lead Production. 

(vi) Pulp and Paper Manufacturing. 

(vii) Zinc Production. 

(3) A facility that in any calendar year starting in 

2010 meets all three of the conditions listed in this 

paragraph (a)(3). For these facilities, the annual GHG 

report must cover emissions from stationary fuel combustion 

sources only. 

(i) The facility does not meet the requirements of 

either paragraph (a)(1) or (a)(2) of this section. 

(ii) The aggregate maximum rated heat input capacity 

of the stationary fuel combustion units at the facility is 

30 mmBtu/hr or greater. 

(iii) The facility emits 25,000 metric tons CO2e or 

more per year in combined emissions from all stationary 

fuel combustion sources. 

(4) A supplier (as defined in subparts KK through PP 

of this part) that provides products listed in this 

paragraph (a)(4) in any calendar year starting in 2010. 

For these suppliers, the annual GHG report must cover all 

applicable products for which calculation methodologies are 

provided in subparts KK through PP of this part. 

(i) Coal-to-liquids suppliers, as specified in this 

paragraph (i). 
5

(A) All producers of coal-to-liquid products. 

(B) Importers of an annual quantity of coal-to-liquid 

products that is equivalent to 25,000 metric tons CO2e or 

more. 

(C) Exporters of an annual quantity of coal-to-liquid 

products is equivalent to 25,000 metric tons CO2e or more. 

(ii) Petroleum product suppliers, as specified in 

this paragraph (ii): 

(A) All petroleum refineries that distill crude oil. 

(B) Importers of an annual quantity of petroleum 

products that is equivalent to 25,000 metric tons CO2e or 

more. 

(C) Exporters of an annual quantity of petroleum 

products that is equivalent to 25,000 metric tons CO2e or 

more. 

(iii) Natural gas and natural gas liquids suppliers, 

as specified in this paragraph (iii): 

(A) All natural gas fractionators. 

(B) All local natural gas distribution companies. 

(iv) Industrial greenhouse gas suppliers, as 

specified in this paragraph (iv): 

(A) All producers of industrial greenhouse gases. 

(B) Importers of industrial greenhouse gases with 

annual bulk imports of N2O, fluorinated GHG, and CO2 that in 
6

combination are equivalent to 25,000 metric tons CO2e or 

more. 

(C) Exporters of industrial greenhouse gases with 

annual bulk exports of N2O, fluorinated GHG, and CO2 that in 

combination are equivalent to 25,000 metric tons CO2e or 

more. 

(v) Carbon dioxide suppliers, as specified in this 

paragraph (v). 

(A) All producers of CO2. 

(B) Importers of CO2 with annual bulk imports of N2O, 

fluorinated GHG, and CO2 that in combination are equivalent 

to 25,000 metric tons CO2e or more. 

(C) Exporters of CO2 with annual bulk exports of N2O, 

fluorinated GHG, and CO2 that in combination are equivalent 

to 25,000 metric tons CO2e or more. 

(5) Research and development activities are not 

considered to be part of any source category defined in 

this part. 

(b) To calculate GHG emissions for comparison to the 

25,000 metric ton CO2e per year emission threshold in 

paragraph (a)(2) of this section, the owner or operator 

shall calculate annual CO2e emissions, as described in 

paragraphs (b)(1) through (b)(4) of this section. 
7

(1) Calculate the annual emissions of CO2, CH4, 

N2O,and each fluorinated GHG in metric tons from all 

applicable source categories listed in paragraph (a)(2) of 

this section. The GHG emissions shall be calculated using 

the calculation methodologies specified in each applicable 

subpart and available company records. Include emissions 

from only those gases listed in Table A-1 of this subpart. 

(2) For each general stationary fuel combustion unit, 

calculate the annual CO2 emissions in metric tons using any 

of the four calculation methodologies specified in 

§98.33(a). Calculate the annual CH4 and N2O emissions from 

the stationary fuel combustion sources in metric tons using 

the appropriate equation in §98.33(c). Exclude carbon 

dioxide emissions from the combustion of biomass, but 

include emissions of CH4 and N2O from biomass combustion. 

(3) For miscellaneous uses of carbonate, calculate 

the annual CO2 emissions in metric tons using the procedures 

specified in subpart U of this part. 

(4) Sum the emissions estimates from paragraphs 

(b)(1), (b)(2), and (b)(3) of this section for each GHG and 

calculate metric tons of CO2e using Equation A-1 of this 

section. 

∑

=

=

n

i 1 i

x GWP ie GHG 2CO (Eq. A-1) 
8

Where: 

CO2e = Carbon dioxide equivalent, metric tons/year. 

GHGi = Mass emissions of each greenhouse gas listed in 

Table A-1 of this subpart, metric tons/year. 

GWPi = Global warming potential for each greenhouse gas 

from Table A-1 of this subpart. 

n = The number of greenhouse gases emitted. 

(5) For purpose of determining if an emission 

threshold has been exceeded, include in the emissions 

calculation any CO2 that is captured for transfer off site. 

(c) To calculate GHG emissions for comparison to the 

25,000 metric ton CO2e/year emission threshold for 

stationary fuel combustion under paragraph (a)(3) of this 

section, calculate CO2, CH4, and N2O emissions from each 

stationary fuel combustion unit by following the methods 

specified in paragraph (b)(2) of this section. Then, 

convert the emissions of each GHG to metric tons CO2e per 

year using Equation A-1 of this section, and sum the 

emissions for all units at the facility. 

(d) To calculate GHG quantities for comparison to the 

25,000 metric ton CO2 per year threshold for importers and 

exporters of coal-to-liquid products under paragraph 

(a)(4)(i) of this section, calculate the mass in metric 

tons per year of CO2 that would result from the complete 

combustion or oxidation of the quantity of coal-to-liquid 
9

products that are imported during the reporting year and 

that are exported during the reporting year. Calculate the 

emissions using the methodology specified in subpart LL of 

this part. 

(e) To calculate GHG quantities for comparison to the 

25,000 metric ton CO2e per year threshold for importers and 

exporters of petroleum products under paragraph (a)(4)(ii) 

of this section, calculate the mass in metric tons per year 

of CO2 that would result from the complete combustion or 

oxidation of the volume of petroleum products and natural 

gas liquids that are imported during the reporting year and 

that are exported during the reporting year. Calculate the 

emissions using the methodology specified in subpart MM of 

this part. 

(f) To calculate GHG quantities for comparison to the 

25,000 metric ton CO2e per year threshold under paragraph 

(a)(4) of this section for importers and exporters of 

industrial greenhouse gases and for importers and exporters 

of CO2, the owner or operator shall calculate the mass in 

metric tons per year of CO2e imports and exports as 

described in paragraphs (f)(1) through (f)(3) of this 

section. 

(1) Calculate the mass in metric tons per year of CO2, 

N2O, and each fluorinated GHG that is imported and the mass 
10

in metric tons per year of CO2, N2O, and each fluorinated 

GHG that is exported during the year. Include only those 

gases listed in Table A-1 of this subpart. 

(2) Convert the mass of each imported and each GHG 

exported from paragraph (f)(1) of this section to metric 

tons of CO2e using Equation A-1 of this section. 

(3) Sum the total annual metric tons of CO2e in 

paragraph (f)(2) of this section for all imported GHGs. 

Sum the total annual metric tons of CO2e in paragraph (f)(2) 

of this section for all exported GHGs. 

(g) If a capacity or generation reporting threshold 

in paragraph (a)(1) of this section applies, the owner or 

operator shall review the appropriate records and perform 

any necessary calculations to determine whether the 

threshold has been exceeded. 

(h) An owner or operator of a facility or supplier 

that does not meet the applicability requirements of 

paragraph (a) of this section is not subject to this rule. 

Such owner or operator would become subject to the rule and 

reporting requirements §98.3(b)(3), if a facility or 

supplier exceeds the applicability requirements of 

paragraph (a) of this section at a later time. Thus, the 

owner or operator should reevaluate the applicability to 

this part (including the revising of any relevant emissions 
11

calculations or other calculations) whenever there is any 

change that could cause a facility or supplier to meet the 

applicability requirements of paragraph (a) of this 

section. Such changes include but are not limited to 

process modifications, increases in operating hours, 

increases in production, changes in fuel or raw material 

use, addition of equipment, and facility expansion. 

(i) Except as provided in this paragraph, once a 

facility or supplier is subject to the requirements of this 

part, the owner or operator must continue for each year 

thereafter to comply with all requirements of this part, 

including the requirement to submit annual GHG reports, 

even if the facility or supplier does not meet the 

applicability requirements in paragraph (a) of this section 

in a future year. 

(1) If reported emissions are less than 25,000 metric 

tons CO2e per year for five consecutive years, then the 

owner or operator may discontinue complying with this part 

provided that the owner or operator submits a notification 

to the Administrator that announces the cessation of 

reporting and explains the reasons for the reduction in 

emissions. The notification shall be submitted no later 

than March 31 of the year immediately following the fifth 

consecutive year of emissions less than 25,000 tons CO2e per 
12

year. The owner or operator must maintain the 

corresponding records required under §98.3(g) for each of 

the five consecutive years and retain such records for 

three years following the year that reporting was 

discontinued. The owner or operator must resume reporting 

if annual emissions in any future calendar year increase to 

25,000 metric tons CO2e per year or more. 

(2) If reported emissions are less than 15,000 metric 

tons CO2e per year for three consecutive years, then the 

owner or operator may discontinue complying with this part 

provided that the owner or operator submits a notification 

to the Administrator that announces the cessation of 

reporting and explains the reasons for the reduction in 

emissions. The notification shall be submitted no later 

than March 31 of the year immediately following the third 

consecutive year of emissions less than 15,000 tons CO2e per 

year. The owner or operator must maintain the 

corresponding records required under §98.3(g) for each of 

the three consecutive years and retain such records for 

three years following the year that reporting was 

discontinued. The owner or operator must resume reporting 

if annual emissions in any future calendar year increase to 

25,000 metric tons CO2e per year or more. 
13

(3) If the operations of a facility or supplier are 

changed such that all applicable GHG-emitting processes and 

operations listed in paragraphs (a)(1) through (a)(4) of 

this section cease to operate, then the owner or operator 

is exempt from reporting in the years following the year in 

which cessation of such operations occurs, provided that 

the owner or operator submits a notification to the 

Administrator that announces the cessation of reporting and 

certifies to the closure of all GHG-emitting processes and 

operations. This paragraph (i)(2) does not apply to 

seasonal or other temporary cessation of operations. This 

paragraph (i)(2) does not apply to facilities with 

municipal solid waste landfills. The owner or operator 

must resume reporting for any future calendar year during 

which any of the GHG-emitting processes or operations 

resume operation. 

(j) Table A-2 of this subpart provides a conversion 

table for some of the common units of measure used in part 

98. 

§98.3 What are the general monitoring, reporting, 

recordkeeping and verification requirements of this part?

The owner or operator of a facility or supplier that 

is subject to the requirements of this part must submit GHG 

reports to the Administrator, as specified in this section. 
14

(a) General. Except as provided in paragraph (d) of 

this section, follow the procedures for emission 

calculation, monitoring, quality assurance, missing data, 

recordkeeping, and reporting that are specified in each 

relevant subpart of this part. 

(b) Schedule. The annual GHG report must be 

submitted no later than March 31 of each calendar year for 

GHG emissions in the previous calendar year. 

(1) For an existing facility or supplier that began 

operation before January 1, 2010, report emissions for 

calendar year 2010 and each subsequent calendar year. 

(2) For a new facility or supplier that begins 

operation on or after January 1, 2010, report emissions 

beginning with the first operating month and ending on 

December 31 of that year. Each subsequent annual report 

must cover emissions for the calendar year, beginning on 

January 1 and ending on December 31. 

(3) For any facility or supplier that becomes subject 

to this rule because of a physical or operational change 

that is made after January 1, 2010, report emissions for 

the first calendar year in which the change occurs, 

beginning with the first month of the change and ending on 

December 31 of that year. For a facility or supplier that 

becomes subject to this rule solely because of an increase 
15

in hours of operation or level of production, the first 

month of the change is the month in which the increased 

hours of operation or level of production, if maintained 

for the remainder of the year, would cause the facility or 

supplier to exceed the applicable threshold. Each 

subsequent annual report must cover emissions for the 

calendar year, beginning on January 1 and ending on 

December 31. 

(c) Content of the annual report. Except as provided 

in paragraph (d) of this section, each annual GHG report 

shall contain the following information: 

(1) Facility name or supplier name (as appropriate) 

and physical street address including the city, state, and 

zip code.

(2) Year and months covered by the report. 

(3) Date of submittal. 

(4) For facilities, report annual emissions of CO2, 

CH4, N2O, and each fluorinated GHG (as defined in §98.6) as 

follows: 

(i) Annual emissions (excluding biogenic CO2) 

aggregated for all GHG from all applicable source 

categories in subparts C through JJ of this part and 

expressed in metric tons of CO2e calculated using Equation 

A-1 of this subpart. 
16

(ii) Annual emissions of biogenic CO2 aggregated for 

all applicable source categories in subparts C through JJ 

of this part. 

(iii) Annual emissions from each applicable source 

category in subparts C through JJ of this part, expressed 

in metric tons of each GHG listed in this paragraph 

(4)(iii)(A) through (4)(iii)(E). 

(A) Biogenic CO2. 

(B) CO2 (excluding biogenic CO2). 

(C) CH4. 

(D) N2O. 

(E) Each fluorinated GHG (including those not listed 

in Table A-1 of this subpart). 

(iv) Emissions and other data for individual units. 

processes, activities, and operations as specified in the 

“Data reporting requirements” section of each applicable 

subpart of this part. 

(5) For suppliers, report annual quantities of CO2, 

CH4, N2O, and each fluorinated GHG (as defined in §98.6) that 

would be emitted from combustion or use of the products 

supplied, imported, and exported during the year. Calculate 

and report quantities at the following levels: 

(i) Total quantity of GHG aggregated for all GHG from 

all applicable supply categories in subparts KK through PP 
17

of this part and expressed in metric tons of CO2e calculated 

using Equation A-1 of this subpart. 

(ii) Quantity of each GHG from each applicable supply 

category in subparts KK through PP of this part, expressed 

in metric tons of each GHG. For fluorinated GHG, report 

emissions of all fluorinated GHG, including those not 

listed in Table A-1 of this subpart. 

(iii) Any other data specified in the “Data reporting 

requirements” section of each applicable subpart of this 

part. 

(6) A written explanation, as required under 

§98.3(e), if you change emission calculation methodologies 

during the reporting period. 

(7) A brief description of each “best available 

monitoring method” used according to paragraph (d) of this 

section, the parameter measured using the method, and the 

time period during which the “best available monitoring 

method” was used. 

(8) Each data element for which a missing data 

procedure was used according to the procedures of an 

applicable subpart and the total number of hours in the 

year that a missing data procedure was used for each data 

element. 
18

(9) A signed and dated certification statement 

provided by the designated representative of the owner or 

operator, according to the requirements of §98.4(e)(1). 

(d) Special provisions for reporting year 2010. 

(1) Best available monitoring methods. During 

January 1, 2010 through March 31, 2010, owners or operators 

may use best available monitoring methods for any parameter 

(e.g., fuel use, daily carbon content of feedstock by 

process line) that cannot reasonably be measured according 

to the monitoring and QA/QC requirements of a relevant 

subpart. The owner or operator must use the calculation 

methodologies and equations in the “Calculating GHG 

Emissions” sections of each relevant subpart, but may use 

the best available monitoring method for any parameter for 

which it is not reasonably feasible to acquire, install, 

and operate a required piece of monitoring equipment by 

January 1, 2010. Starting no later than April 1, 2010, the 

owner or operator must discontinue using best available 

methods and begin following all applicable monitoring and 

QA/QC requirements of this part, except as provided in 

paragraphs (d)(2) and (d)(3) of this section. Best 

available monitoring methods means any of the following 

methods specified in this paragraph: 
19

(i) Monitoring methods currently used by the facility 

that do not meet the specifications of an relevant subpart. 

(ii) Supplier data. 

(iii) Engineering calculations. 

(iv) Other company records. 

(2) Requests for extension of the use of best 

available monitoring methods. The owner or operator may 

submit a request to the Administrator to use one or more 

best available monitoring methods beyond March 31, 2010. 

(i) Timing of request. The extension request must be 

submitted to EPA no later than 30 days after the effective 

date of the GHG reporting rule. 

(ii) Content of request. Requests must contain the 

following information: 

(A) A list of specific item of monitoring 

instrumentation for which the request is being made and the 

locations where each piece of monitoring instrumentation 

will be installed. 

(B) Identification of the specific rule requirements 

(by rule subpart, section, and paragraph numbers) for which 

the instrumentation is needed. 

(C) A description of the reasons why the needed 

equipment could not be obtained and installed before April 

1, 2010. 
20

(D) If the reason for the extension is that the 

equipment cannot be purchased and delivered by April 1, 

2010, include supporting documentation such as the date the 

monitoring equipment was ordered, investigation of 

alternative suppliers and the dates by which alternative 

vendors promised delivery, backorder notices or unexpected 

delays, descriptions of actions taken to expedite delivery, 

and the current expected date of delivery. 

(E) If the reason for the extension is that the 

equipment cannot be installed without a process unit 

shutdown, include supporting documentation demonstrating 

that it is not practicable to isolate the equipment and 

install the monitoring instrument without a full process 

unit shutdown. Include the date of the most recent process 

unit shutdown, the frequency of shutdowns for this process 

unit, and the date of the next planned shutdown during 

which the monitoring equipment can be installed. If there 

has been a shutdown or if there is a planned process unit 

shutdown between promulgation of this part and April 1, 

2010, include a justification of why the equipment could 

not be obtained and installed during that shutdown. 

(F) A description of the specific actions the 

facility will take to obtain and install the equipment as 
21

soon as reasonably feasible and the expected date by which 

the equipment will be installed and operating. 

(iii) Approval Criteria. To obtain approval, the 

owner or operator must demonstrate to the Administrator’s 

satisfaction that it is not reasonably feasible to acquire, 

install, and operate a required piece of monitoring 

equipment by April 1, 2010. The use of best available 

methods will not be approved beyond December 31, 2010. 

(3) Abbreviated emissions report for facilities 

containing only general stationary fuel combustion sources. 

In lieu of the report required by paragraph (c) of this 

section, the owner or operator of an existing facility that 

is in operation on January 1, 2010 and that meets the 

conditions of §98.2 (a)(3) may submit an abbreviated GHG 

report for the facility for GHGs emitted in 2010. The 

abbreviated report must be submitted by March 31, 2011. An 

owner or operator that submits an abbreviated report must 

submit a full GHG report according to the requirements of 

paragraph (c) of this section beginning in calendar year 

2011. The abbreviated facility report must include the 

following information: 

(i) Facility name and physical street address 

including the city, state and zip code. 

(ii) The year and months covered by the report. 
22

(iii) Date of submittal. 

(iv) Total facility GHG emissions aggregated for all 

stationary fuel combustion units calculated according to 

any method specified in §98.33(a) and expressed in metric 

tons of CO2, CH4, N2O, and CO2e. 

(v) Any facility operating data or process 

information used for the GHG emission calculations. 

(vi) A signed and dated certification statement 

provided by the designated representative of the owner or 

operator, according to the requirements of paragraph (e)(1) 

of this section. 

(e) Emission Calculations. In preparing the GHG 

report, you must use the calculation methodologies 

specified in the relevant subparts, except as specified in 

paragraph (d) of this section. For each source category, 

you must use the same calculation methodology throughout a 

reporting period unless you provide a written explanation 

of why a change in methodology was required. 

(f) Verification. To verify the completeness and 

accuracy of reported GHG emissions, the Administrator may 

review the certification statements described in paragraphs 

(c)(8) and (d)(3)(vi) of this section and any other 

credible evidence, in conjunction with a comprehensive 

review of the GHG reports and periodic audits of selected 
23

reporting facilities. Nothing in this section prohibits 

the Administrator from using additional information to 

verify the completeness and accuracy of the reports. 

(g) Recordkeeping. An owner or operator that is 

required to report GHGs under this part must keep records 

as specified in this paragraph. Retain all required 

records for at least 3 years. The records shall be kept in 

an electronic or hard-copy format (as appropriate) and 

recorded in a form that is suitable for expeditious 

inspection and review. Upon request by the Administrator, 

the records required under this section must be made 

available to EPA. Records may be retained off site if the 

records are readily available for expeditious inspection 

and review. For records that are electronically generated 

or maintained, the equipment or software necessary to read 

the records shall be made available, or, if requested by 

EPA, electronic records shall be converted to paper 

documents. You must retain the following records, in 

addition to those records prescribed in each applicable 

subpart of this part: 

(1) A list of all units, operations, processes, and 

activities for which GHG emission were calculated. 

(2) The data used to calculate the GHG emissions for 

each unit, operation, process, and activity, categorized by 
24

fuel or material type. These data include but are not 

limited to the following information in this paragraph 

(g)(2): 

(i) The GHG emissions calculations and methods used. 

(ii) Analytical results for the development of sitespecific emissions factors. 

(iii) The results of all required analyses for high 

heat value, carbon content, and other required fuel or 

feedstock parameters. 

(iv) Any facility operating data or process 

information used for the GHG emission calculations. 

(3) The annual GHG reports. 

(4) Missing data computations. For each missing data 

event, also retain a record of the duration of the event, 

actions taken to restore malfunctioning monitoring 

equipment, the cause of the event, and the actions taken to 

prevent or minimize occurrence in the future. 

(5) A written GHG Monitoring Plan. 

(i) At a minimum, the GHG Monitoring Plan shall 

include the elements listed in this paragraph (i). 

(A) Identification of positions of responsibility 

(i.e., job titles) for collection of the emissions data. 

(B) Explanation of the processes and methods used to 

collect the necessary data for the GHG calculations. 
25

(C) Description of the procedures and methods that 

are used for quality assurance, maintenance, and repair of 

all continuous monitoring systems, flow meters, and other 

instrumentation used to provide data for the GHGs reported 

under this part. 

(ii) The GHG Monitoring Plan may rely on references 

to existing corporate documents (e.g., standard operating 

procedures, quality assurance programs under appendix F to 

40 CFR part 60 or appendix B to 40 CFR part 75, and other 

documents) provided that the elements required by paragraph 

(g)(5)(i) of this section are easily recognizable. 

(iii) The owner or operator shall revise the GHG 

Monitoring Plan as needed to reflect changes in production 

processes, monitoring instrumentation, and quality 

assurance procedures; or to improve procedures for the 

maintenace and repair of monitoring systems to reduce the 

frequency of monitoring equipment downtime. 

(iv) Upon request by the Administrator, the owner or 

operator shall make all information that is collected in 

conformance with the GHG Monitoring Plan available for 

review during an audit. Electronic storage of the 

information in the plan is permissible, provided that the 

information can be made available in hard copy upon request 

during an audit. 
26

(6) The results of all required certification and 

quality assurance tests of continuous monitoring systems, 

fuel flow meters, and other instrumentation used to provide 

data for the GHGs reported under this part. 

(7) Maintenance records for all continuous monitoring 

systems, flow meters, and other instrumentation used to 

provide data for the GHGs reported under this part. 

(h) Annual GHG report revisions. The owner or 

operator shall submit a revised report within 45 days of 

discovering or being notified by EPA of errors in an annual 

GHG report. The revised report must correct all identified 

errors. The owner or operator shall retain documentation 

for 3 years to support any revisions made to an annual GHG 

report. 

(i) Calibration Accuracy Requirements. The owner or 

operator of a facility or supplier that is subject to the 

requirements of this part must meet the calibration 

accuracy requirements of this paragraph (i). 

(1) Except as provided paragraphs (i)(4) through 

(i)(6) of this section, flow meters and other devices 

(e.g., belt scales) that measure data used to calculate GHG 

emissions shall be calibrated prior to April 1, 2010 using 

the procedures specified in this paragraph and each 

relevant subpart of this part. All measurement devices must 
27

be calibrated according to the manufacturer’s recommended 

procedures, an appropriate industry consensus standard, or 

a method specified in a relevant subpart of this part. All 

measurement devices shall be calibrated to an accuracy of 5 

percent. For facilities and suppliers that become subject 

to this part after April 1, 2010, the initial calibration 

shall be conducted on the date that data collection is 

required to begin. Subsequent calibrations shall be 

performed at the frequency specified in each applicable 

subpart. 

(2) For flow meters, perform all calibrations at 

measurement points that are representative of normal 

operation of the meter. Except for the orifice, nozzle, 

and venturi flow meters described in paragraph (i)(3) of 

this section, calculate the calibration error at each 

measurement point using Equation A-2 of this section. The 

terms “R” and “A” in Equation A-2 must be expressed in 

consistent units of measure (e.g., gallons/minute, ft3/min). 

The calibration error at each measurement point shall not 

exceed 5.0 percent of the reference value. 

x 100

R

R A

CE −

= (Eq. A-2) 

Where: 
28

CE = Calibration error (%) 

R = Reference value 

A = Flow meter response to the reference value 

(3) For orifice, nozzle, and venturi flow meters, the 

initial quality assurance consists of in-situ calibration 

of the differential pressure (delta-P), total pressure, and 

temperature transmitters. Calibrate each transmitter at a 

zero point and at least one upscale point. Fixed reference 

points, such as the freezing point of water, may be used 

for temperature transmitter calibrations. Calculate the 

calibration error of each transmitter at each measurement 

point, using Equation A-3 of this subpart. The terms “R”, 

“A”, and “FS” in Equation A-3 of this subpart must be in 

consistent units of measure (e.g., milliamperes, inches of 

water, psi, degrees). For each transmitter, the CE value 

at each measurement point shall not exceed 2.0 percent of 

full-scale. Alternatively, the results are acceptable if 

the sum of the calculated CE values for the three 

transmitters at each calibration level (i.e., at the zero 

level and at each upscale level) does not exceed 5.0 

percent. 

x 100

FS

R A

CE −= (Eq. A-3) 

Where: 

CE = Calibration error (%) 
29

R = Reference value 

A = Transmitter response to the reference value 

FS = Full-scale value of the transmitter 

(4) Fuel billing meters are exempted from the 

calibration requirements of this section, provided that the 

fuel supplier and any unit combusting the fuel do not have 

any common owners and are not owned by subsidiaries or 

affiliates of the same company. 

(5) For a flow meter or other measurement device that 

has been previously calibrated in accordance with this 

part, an initial calibration is not required by the date 

specified in paragraph (i)(1) of this section if, as of the 

date required for the initial calibration, the previous 

calibration is still active (i.e., the device is not yet 

due for recalibration because the time interval between 

successive calibrations, as required by this part, has not 

elapsed). 

(6) For units and processes that operate continuously 

with infrequent outages, it may not be possible to meet the 

April 1, 2010 deadline for the initial calibration of a 

flow meter or other measurement device without removing the 

device from service and shipping it to a remote location, 

thereby disrupting normal process operation. In such 

cases, the owner or operator may postpone the initial 
30

calibration until the next scheduled maintenance outage, 

and may similarly postpone the subsequent recalibrations. 

Such postponements shall be documented in the monitoring 

plan that is required under §98.3(g)(5). 

§98.4 Authorization and Responsibilities of the Designated

Representative.

(a) General. Except as provided under paragraph (f) 

of this section, each facility, and each supplier, that is 

subject to this part, shall have one and only one 

designated representative, who shall be responsible for 

certifying, signing, and submitting GHG emissions reports 

and any other submissions for such facility and supplier 

respectively to the Administrator under this part. If the 

facility is required under any other part of title 40 of 

the Code of Federal Regulations to submit to the 

Administrator any other emission report that is subject to 

any requirement in 40 CFR part 75, the same individual 

shall be the designated representative responsible for 

certifying, signing, and submitting the GHG emissions 

reports and all such other emissions reports under this 

part. 

(b) Authorization of a designated representative. 

The designated representative of the facility or supplier 

shall be an individual selected by an agreement binding on 
31

the owners and operators of such facility or supplier and 

shall act in accordance with the certification statement in 

paragraph (i)(4)(iv) of this section. 

(c) Responsibility of the designated representative. 

Upon receipt by the Administrator of a complete certificate 

of representation under this section for a facility or 

supplier, the designated representative identified in such 

certificate of representation shall represent and, by his 

or her representations, actions, inactions, or submissions, 

legally bind each owner and operator of such facility or 

supplier in all matters pertaining to this part, 

notwithstanding any agreement between the designated 

representative and such owners and operators. The owners 

and operators shall be bound by any decision or order 

issued to the designated representative by the 

Administrator or a court. 

(d) Timing. No GHG emissions report or other 

submissions under this part for a facility or supplier will 

be accepted until the Administrator has received a complete 

certificate of representation under this section for a 

designated representative of the facility or supplier. Such 

certificate of representation shall be submitted at least 

60 days before the deadline for submission of the 
32

facility’s or supplier’s initial emission report under this 

part. 

(e) Certification of the GHG emissions report. Each 

GHG emission report and any other submission under this 

part for a facility or supplier shall be certified, signed, 

and submitted by the designated representative or any 

alternate designated representative of the facility or 

supplier in accordance with this section and §3.10. 

(1) Each such submission shall include the following 

certification statement signed by the designated 

representative or any alternate designated representative: 

“I am authorized to make this submission on behalf of the 

owners and operators of the facility or supplier, as 

applicable, for which the submission is made. I certify 

under penalty of law that I have personally examined, and 

am familiar with, the statements and information submitted 

in this document and all its attachments. Based on my 

inquiry of those individuals with primary responsibility 

for obtaining the information, I certify that the 

statements and information are to the best of my knowledge 

and belief true, accurate, and complete. I am aware that 

there are significant penalties for submitting false 

statements and information or omitting required statements 
33

and information, including the possibility of fine or 

imprisonment.” 

(2) The Administrator will accept a GHG emission 

report or other submission for a facility or supplier under 

this part only if the submission is certified, signed, and 

submitted in accordance with this section. 

(f) Alternate designated representative. A 

certificate of representation under this section for a 

facility or supplier may designate one alternate designated 

representative, who shall be an individual selected by an 

agreement binding on the owners and operators, and may act 

on behalf of the designated representative, of such 

facility or supplier. The agreement by which the alternate 

designated representative is selected shall include a 

procedure for authorizing the alternate designated 

representative to act in lieu of the designated 

representative. 

(1) Upon receipt by the Administrator of a complete 

certificate of representation under this section for a 

facility or supplier identifying an alternate designated 

representative. 

(i) The alternate designated representative may act 

on behalf of the designated representative for such 

facility or supplier. 
34

(ii) Any representation, action, inaction, or 

submission by the alternate designated representative shall 

be deemed to be a representation, action, inaction, or 

submission by the designated representative. 

(2) Except in this section, whenever the term 

“designated representative” is used in this part, the term 

shall be construed to include the designated representative 

or any alternate designated representative. 

(g) Changing a designated representative or alternate 

designated representative. The designated representative 

or alternate designated representative identified in a 

complete certificate of representation under this section 

for a facility or supplier received by the Administrator 

may be changed at any time upon receipt by the 

Administrator of another later signed, complete certificate 

of representation under this section for the facility or 

supplier. Notwithstanding any such change, all 

representations, actions, inactions, and submissions by the 

previous designated representative or the previous 

alternate designated representative of the facility or 

supplier before the time and date when the Administrator 

receives such later signed certificate of representation 

shall be binding on the new designated representative and 

the owners and operators of the facility or supplier. 
35

(h) Changes in owners and operators. In the event an 

owner or operator of the facility or supplier is not 

included in the list of owners and operators in the 

certificate of representation under this section for the 

facility or supplier, such owner or operator shall be 

deemed to be subject to and bound by the certificate of 

representation, the representations, actions, inactions, 

and submissions of the designated representative and any 

alternate designated representative of the facility or 

supplier, as if the owner or operator were included in such 

list. Within 90 days after any change in the owners and 

operators of the facility or supplier (including the 

addition of a new owner or operator), the designated 

representative or any alternate designated representative 

shall submit a certificate of representation that is 

complete under this section except that such list shall be 

amended to reflect the change. If the designated 

representative or alternate designated representative 

determines at any time that an owner or operator of the 

facility or supplier is not included in such list and such 

exclusion is not the result of a change in the owners and 

operators, the designated representative or any alternate 

designated representative shall submit, within 90 days of 

making such determination, a certificate of representation 
36

that is complete under this section except that such list 

shall be amended to include such owner or operator. 

(i) Certificate of representation. A certificate of 

representation shall be complete if it includes the 

following elements in a format prescribed by the 

Administrator in accordance with this section: 

(1) Identification of the facility or supplier for 

which the certificate of representation is submitted. 

(2) The name, address, e-mail address (if any), 

telephone number, and facsimile transmission number (if 

any) of the designated representative and any alternate 

designated representative. 

(3) A list of the owners and operators of the 

facility or supplier identified in paragraph (i)(1) of this 

section, provided that, if the list includes the operators 

of the facility or supplier and the owners with control of 

the facility or supplier, the failure to include any other 

owners shall not make the certificate of representation 

incomplete. 

(4) The following certification statements by the 

designated representative and any alternate designated 

representative: 

(i) “I certify that I was selected as the designated 

representative or alternate designated representative, as 
37

applicable, by an agreement binding on the owners and 

operators of the facility or supplier, as applicable.” 

(ii) “I certify that I have all the necessary 

authority to carry out my duties and responsibilities under 

40 CFR part 98 on behalf of the owners and operators of the 

facility or supplier, as applicable, and that each such 

owner and operator shall be fully bound by my 

representations, actions, inactions, or submissions.” 

(iii) “I certify that the owners and operators of the 

facility or supplier, as applicable, shall be bound by any 

order issued to me by the Administrator or a court 

regarding the facility or supplier.” 

(iv) “If there are multiple owners and operators of 

the facility or supplier, as applicable, I certify that I 

have given a written notice of my selection as the 

‘designated representative’ or ‘alternate designated 

representative’, as applicable, and of the agreement by 

which I was selected to each owner and operator of the 

facility or supplier." 

(5) The signature of the designated representative 

and any alternate designated representative and the dates 

signed. 

(j) Documents of agreement. Unless otherwise 

required by the Administrator, documents of agreement 
38

referred to in the certificate of representation shall not 

be submitted to the Administrator. The Administrator shall 

not be under any obligation to review or evaluate the 

sufficiency of such documents, if submitted. 

(k) Binding nature of the certificate of 

representation. Once a complete certificate of 

representation under this section for a facility or 

supplier has been received, the Administrator will rely on 

the certificate of representation unless and until a later 

signed, complete certificate of representation under this 

section for the facility or supplier is received by the 

Administrator. 

(l) Objections concerning a designated 

representative. 

(1) Except as provided in paragraph (g) of this 

section, no objection or other communication submitted to 

the Administrator concerning the authorization, or any 

representation, action, inaction, or submission, of the 

designated representative or alternate designated 

representative shall affect any representation, action, 

inaction, or submission of the designated representative or 

alternate designated representative, or the finality of any 

decision or order by the Administrator under this part. 
39

(2) The Administrator will not adjudicate any private 

legal dispute concerning the authorization or any 

representation, action, inaction, or submission of any 

designated representative or alternate designated 

representative. 

(m) Delegation by designated representative and 

alternate designated representative. 

(1) A designated representative or an alternate 

designated representative may delegate his or her own 

authority, to one or more individuals, to submit an 

electronic submission to the Administrator provided for or 

required under this part, except for a submission under 

this paragraph. 

(2) In order to delegate his or her own authority, to 

one or more individuals, to submit an electronic submission 

to the Administrator in accordance with paragraph (m) (1) 

of this section, the designated representative or alternate 

designated representative must submit electronically to the 

Administrator a notice of delegation, in a format 

prescribed by the Administrator, that includes the 

following elements: 

(i) The name, address, e-mail address (if any), 

telephone number, and facsimile transmission number (if 
40

any) of such designated representative or alternate 

designated representative. 

(ii) The name, address, e-mail address, telephone 

number, and facsimile transmission number (if any) of each 

such individual (referred to as an “agent”). 

(iii) For each such individual, a list of the type or 

types of electronic submissions under paragraph (m)(1) of 

this section for which authority is delegated to him or 

her. 

(iv) For each type of electronic submission listed in 

accordance with clause (iii), the facility or supplier for 

which the electronic submission may be made. 

(v) The following certification statements by such 

designated representative or alternate designated 

representative: 

(A) “I agree that any electronic submission to the 

Administrator that is by an agent identified in this notice 

of delegation and of a type listed, and for a facility or 

supplier designated, for such agent in this notice of 

delegation and that is made when I am a designated 

representative or alternate designated representative, as 

applicable, and before this notice of delegation is 

superseded by another notice of delegation under 
41

§98.4(m)(3) shall be deemed to be an electronic submission 

certified, signed, and submitted by me.” 

(B) “Until this notice of delegation is superseded by 

a later signed notice of delegation under §98.4(m)(3), I 

agree to maintain an e-mail account and to notify the 

Administrator immediately of any change in my e-mail 

address unless all delegation of authority by me under 

§98.4(m) is terminated.”. 

(vi) The signature of such designated representative 

or alternate designated representative and the date signed. 

(3) A notice of delegation submitted in accordance 

with paragraph (m)(2) of this section shall be effective, 

with regard to the designated representative or alternate 

designated representative identified in such notice, upon 

receipt of such notice by the Administrator and until 

receipt by the Administrator of another such notice that 

was signed later by such designated representative or 

alternate designated representative, as applicable. The 

later signed notice of delegation may replace any 

previously identified agent, add a new agent, or eliminate 

entirely any delegation of authority. 

(4) Any electronic submission covered by the 

certification in paragraph (m)(2)(iv)(A) of this section 

and made in accordance with a notice of delegation 
42

effective under paragraph (m)(3) of this section shall be 

deemed to be an electronic submission certified, signed, 

and submitted by the designated representative or alternate 

designated representative submitting such notice of 

delegation. 

§98.5 How is the report submitted?

Each GHG report and certificate of representation for 

a facility or supplier must be submitted electronically in 

accordance with the requirements of §98.4 and in a format 

specified by the Administrator. 

§98.6 Definitions.

All terms used in this part shall have the same 

meaning given in the Clean Air Act and in this section. 

Accuracy of a measurement at a specified level (e.g., 

one percent of full scale or one percent of the value 

measured) means that the mean of repeat measurements made 

by a device or technique are within 95 percent of the range 

bounded by the true value plus or minus the specified 

level. 

Acid Rain Program means the program established under 

title IV of the Clean Air Act, and implemented under parts 

72 through 78 of this chapter for the reduction of sulfur 

dioxide and nitrogen oxides emissions. 
43

Administrator means the Administrator of the United 

States Environmental Protection Agency or the 

Administrator’s authorized representative. 

AGA means the American Gas Association 

Alkali bypass means a duct between the feed end of the 

kiln and the preheater tower through which a portion of the 

kiln exit gas stream is withdrawn and quickly cooled by air 

or water to avoid excessive buildup of alkali, chloride 

and/or sulfur on the raw feed. This may also be referred 

to as the “kiln exhaust gas bypass.” 

Anaerobic digester means the system where wastes are 

collected and anaerobically digested in large containment 

vessels or covered lagoons. Anaerobic digesters stabilize 

waste by the microbial reduction of complex organic 

compounds to CO2 and CH4, which is captured and may be 

flared or used as fuel. Anaerobic digestion systems, 

include but are not limited to covered lagoon, complete 

mix, plug flow, and fixed film digesters. 

Anaerobic lagoon means a type of liquid storage system 

component, either at manure management system or a 

wastewater treatment system, that is designed and operated 

to stabilize wastes using anaerobic microbial processes. 

Anaerobic lagoons may be designed for combined 

stabilization and storage with varying lengths of retention 
44

time (up to a year or greater), depending on the climate 

region, the volatile solids loading rate, and other 

operational factors.

Anode effect is a process upset condition of an 

aluminum electrolysis cell caused by too little alumina 

dissolved in the electrolyte. The anode effect begins when 

the voltage rises rapidly and exceeds a threshold voltage, 

typically 8 volts. 

Anode Effect Minutes Per Cell Day (24 hours) are the 

total minutes during which an electrolysis cell voltage is 

above the threshold voltage, typically 8 volts. 

ANSI means the American National Standards Institute. 

API means the American Petroleum Institute. 

ASABE means the American Society of Agricultural and 

Biological Engineers. 

ASME means the American Society of Mechanical 

Engineers. 

ASTM means the American Society of Testing and 

Materials. 

Asphalt means a dark brown-to-black cement-like 

material obtained by petroleum processing and containing 

bitumens as the predominant component. It includes crude 

asphalt as well as the following finished products: 

cements, fluxes, the asphalt content of emulsions 

Deleted: Argon-oxygen 

decarburization (AOD) vessel

means any closed-bottom, 

refractory-lined converter 

vessel with submerged 

tuyeres through which 

gaseous mixtures containing 

argon and oxygen or nitrogen 

may be blown into molten 

steel for further refining 

to reduce the carbon content 

of the steel.¶
45

(exclusive of water), and petroleum distillates blended 

with asphalt to make cutback asphalts. 

Aviation Gasoline means a complex mixture of volatile 

hydrocarbons, with or without additives, suitably blended 

to be used in aviation reciprocating engines. 

Specifications can be found in ASTM Specification D910–07a, 

Standard Specification for Aviation Gasolines (incorporated 

by reference, see §98.7). 

B0 means the maximum CH4 producing capacity of a waste 

stream, kg CH4/kg COD. 

Basic oxygen furnace means any refractory-lined vessel 

in which high-purity oxygen is blown under pressure through 

a bath of molten iron, scrap metal, and fluxes to produce 

steel. 

bbl means barrel. 

Biodiesel means a mono-akyl ester derived from biomass 

and conforming to ASTM D6751-08, Standard Specification for 

Biodiesel Fuel Blend Stock (B100) for Middle Distillate 

Fuels. 

Biogenic CO2 means carbon dioxide emissions generated 

as the result of biomass combustion from combustion units 

for which emission calculations are required by an 

applicable part 98 subpart. 
46

Biomass means non-fossilized and biodegradable organic 

material originating from plants, animals or microorganisms, including products, by-products, residues and 

waste from agriculture, forestry and related industries as 

well as the non-fossilized and biodegradable organic 

fractions of industrial and municipal wastes, including 

gases and liquids recovered from the decomposition of nonfossilized and biodegradable organic material. 

Blast furnace means a furnace that is located at an 

integrated iron and steel plant and is used for the 

production of molten iron from iron ore pellets and other 

iron bearing materials. 

Blendstocks are petroleum products used for blending 

or compounding into finished motor gasoline. These include 

RBOB (reformulated blendstock for oxygenate blending) and 

CBOB (conventional blendstock for oxygenate blending), but 

exclude oxygenates, butane, and pentanes plus. 

Blendstocks -- Others are products used for blending 

or compounding into finished motor gasoline that are not 

defined elsewhere. Excludes Gasoline Treated as Blendstock 

(GTAB), Diesel Treated as Blendstock (DTAB), conventional 

blendstock for oxygenate blending (CBOB), reformulated 

blendstock for oxygenate blending (RBOB), oxygenates (e.g. 
47

fuel ethanol and methyl tertiary butyl ether), butane, and 

pentanes plus. 

Blowdown mean the act of emptying or depressuring a 

vessel. This may also refer to the discarded material such 

as blowdown water from a boiler or cooling tower. 

British Thermal Unit or Btu means the quantity of heat 

required to raise the temperature of one pound of water by 

one degree Fahrenheit at about 39.2 degrees Fahrenheit. 

Bulk, with respect to industrial GHG suppliers and CO2 

suppliers, means the transfer of a product inside 

containers, including but not limited to tanks, cylinders, 

drums, and pressure vessels. 

Bulk natural gas liquid or NGL refers to mixtures of 

hydrocarbons that have been separated from natural gas as 

liquids through the process of absorption, condensation, 

adsorption, or other methods at lease separators and field 

facilities. Generally, such liquids consist of ethane, 

propane, butanes, and pentanes plus. Bulk NGL is sold to 

fractionators or to refineries and petrochemical plants 

where the fractionation takes place. 

Butane, or n-Butane, is a paraffinic straight-chain 

hydrocarbon with molecular formula C4H10. 

Butylene, or n-Butylene, is an olefinic straight-chain 

hydrocarbon with molecular formula C4H8. 
48

By-product coke oven battery means a group of ovens 

connected by common walls, where coal undergoes destructive 

distillation under positive pressure to produce coke and 

coke oven gas from which by-products are recovered. 

Calcination means the process of thermally treating 

minerals to decompose carbonates from ore. 

Calculation methodology means a methodology prescribed 

under the section “Calculating GHG Emissions” in any 

subpart of part 98. 

Carbon dioxide equivalent or CO2e means the number of 

metric tons of CO2 emissions with the same global warming 

potential as one metric ton of another greenhouse gas, and 

is calculated using Equation A-1 of this subpart. 

Carbon dioxide production well means any hole drilled 

in the earth for the primary purpose of extracting carbon 

dioxide from a geologic formation or group of formations 

which contain deposits of carbon dioxide. 

Carbon dioxide production well facility means one or 

more carbon dioxide production wells that are located on 

one or more contiguous or adjacent properties, which are 

under the control of the same entity. Carbon dioxide 

production wells located on different oil and gas leases, 

mineral fee tracts, lease tracts, subsurface or surface 

unit areas, surface fee tracts, surface lease tracts, or 
49

separate surface sites, whether or not connected by a road, 

waterway, power line, or pipeline, shall be considered part 

of the same CO2 production well facility if they otherwise 

meet the definition. 

Carbon dioxide stream means carbon dioxide that has 

been captured from an emission source (e.g. a power plant 

or other industrial facility) or extracted from a carbon 

dioxide production well plus incidental associated 

substances either derived from the source materials and the 

capture process or extracted with the carbon dioxide. 

Carbon share means the percent of total mass that 

carbon represents in any product.. 

Carbonate means compounds containing the radical CO3

-2. 

Upon calcination, the carbonate radical decomposes to 

evolve carbon dioxide (CO2). Common carbonates consumed in 

the mineral industry include calcium carbonate (CaCO3) or 

calcite; magnesium carbonate (MgCO3) or magnesite; and 

calcium-magnesium carbonate (CaMg(CO3)2) or dolomite. 

Carbonate-based mineral means any of the following 

minerals used in the manufacture of glass: calcium 

carbonate (CaCO3), calcium magnesium carbonate (CaMg(CO3)2), 

sodium carbonate (Na2CO3), barium carbonate (BaCO3), and 

potassium carbonate (K2CO3). 

Deleted: and 
50

Carbonate-based mineral mass fraction means the 

following: for limestone, the mass fraction of CaCO3 in the 

limestone; for dolomite, the mass fraction of CaMg(CO3)2 in 

the dolomite; for soda ash, the mass fraction of Na2CO3 in 

the soda ash; for barium carbonate, the mass fraction of 

BaCO3 in the barium carbonate; and for potassium carbonate, 

the mass fraction of K2CO3 in the potassium carbonate. 

Carbonate-based raw material means any of the 

following materials used in the manufacture of glass: 

limestone, dolomite, soda ash, barium carbonate, and 

potassium carbonate. 

Catalytic cracking unit means a refinery process unit 

in which petroleum derivatives are continuously charged and 

hydrocarbon molecules in the presence of a catalyst are 

fractured into smaller molecules, or react with a contact 

material suspended in a fluidized bed to improve feedstock 

quality for additional processing and the catalyst or 

contact material is continuously regenerated by burning off 

coke and other deposits. Catalytic cracking units include 

both fluidized bed systems, which are referred to as fluid 

catalytic cracking units (FCCU), and moving bed systems, 

which are also referred to as thermal catalytic cracking 

units. The unit includes the riser, reactor, regenerator, 

air blowers, spent catalyst or contact material stripper, 

Deleted: and 

Deleted: and 
51

catalyst or contact material recovery equipment, and 

regenerator equipment for controlling air pollutant 

emissions and for heat recovery.

Deep bedding systems for cattle swine means a manure 

management system in which, as manure accumulates, bedding 

is continually added to absorb moisture over a production 

cycle and possibly for as long as 6 to 12 months. This 

manure management system also is known as a bedded pack 

manure management system and may be combined with a dry lot 

or pasture. 

CBOB-Summer (conventional blendstock for oxygenate 

blending) means a petroleum product which, when blended 

with a specified type and percentage of oxygenate, meets 

the definition of Conventional-Summer. 

CBOB-Winter (conventional blendstock for oxygenate 

blending) means a petroleum product which, when blended 

with a specified type and percentage of oxygenate, meets 

the definition of Conventional-Winter. 

Certified standards means calibration gases certified 

by the manufacturer of the calibration gases to be accurate 

to within 2 percent of the value on the label or 

calibration gases. 

CH4 means methane. 
52

Chemical recovery combustion unit means a combustion 

device, such as a recovery furnace or fluidized-bed reactor 

where spent pulping liquor from sulfite or semi-chemical 

pulping processes is burned to recover pulping chemicals. 

Chemical recovery furnace means an enclosed combustion 

device where concentrated spent liquor produced by the 

kraft or soda pulping process is burned to recover pulping 

chemicals and produce steam. Includes any recovery furnace 

that burns spent pulping liquor produced from both the 

kraft and soda pulping processes. 

Chloride process means a production process where 

titanium dioxide is produced using calcined petroleum coke 

and chlorine as raw materials. 

City gate means a location at which natural gas 

ownership or control passes from one party to another, 

neither of which is the ultimate consumer. In this rule, 

in keeping with common practice, the term refers to a point 

or measuring station at which a local gas distribution 

utility receives gas from a natural gas pipeline company or 

transmission system. Meters at the city gate station 

measure the flow of natural gas into the local distribution 

company system and typically are used to measure local 

distribution company system sendout to customers. 

CO2 means carbon dioxide. 
53

Coal means all solid fuels classified as anthracite, 

bituminous, sub-bituminous, or lignite by the American 

Society for Testing and Materials Designation ASTM D388–05 

Standard Classification of Coals by Rank (incorporated by 

reference, see §98.7). 

COD means the chemical oxygen demand as determined 

using methods specified pursuant to 40 CFR part 136. 

Coke burn-off means the coke removed from the surface 

of a catalyst by combustion during catalyst regeneration. 

Coke burn-off also means the coke combusted in fluid coking 

unit burner. 

Cokemaking means the production of coke from coal in 

either a by-product coke oven battery or a non-recovery 

coke oven battery. 

Commercial Applications means executing a commercial 

transaction subject to a contract. A commercial application 

includes transferring custody of a product from one 

facility to another if it otherwise meets the definition. 

Company records means, in reference to the amount of 

fuel consumed by a stationary combustion unit (or by a 

group of such units), a complete record of the methods 

used, the measurements made, and the calculations performed 

to quantify fuel usage. Company records may include, but 

are not limited to, direct measurements of fuel consumption 
54

by gravimetric or volumetric means, tank drop measurements, 

and calculated values of fuel usage obtained by measuring 

auxiliary parameters such as steam generation or unit 

operating hours. Fuel billing records obtained from the 

fuel supplier qualify as company records. 

Connector means to flanged, screwed, or other joined 

fittings used to connect pipe line segments, tubing, pipe 

components (such as elbows, reducers, “T’s” or valves) or a 

pipe line and a piece of equipment or an instrument to a 

pipe, tube or piece of equipment. A common connector is a 

flange. Joined fittings welded completely around the 

circumference of the interface are not considered 

connectors for the purpose of this part. 

Container glass means glass made of soda-lime recipe, 

clear or colored, which is pressed and/or blown into 

bottles, jars, ampoules, and other products listed in North 

American Industry Classification System 327213 (NAICS 

327213). 

Continuous emission monitoring system or CEMS means 

the total equipment required to sample, analyze, measure, 

and provide, by means of readings recorded at least once 

every 15 minutes, a permanent record of gas concentrations, 

pollutant emission rates, or gas volumetric flow rates from 

stationary sources. 
55

Continuous glass melting furnace means a glass melting 

furnace that operates continuously except during periods of 

maintenance, malfunction, control device installation, 

reconstruction, or rebuilding. 

Conventional—Summer refers to finished gasoline 

formulated for use in motor vehicles, the composition and 

properties of which do not meet the requirements of the 

reformulated gasoline regulations promulgated by the U.S. 

Environmental Protection Agency under 40 CFR 80.40, but 

which meet summer RVP standards required under 40 CFR 80.27 

or as specified by the state. Note: This category excludes 

conventional gasoline for oxygenate blending (CBOB) as well 

as other blendstock. 

Conventional—Winter refers to finished gasoline 

formulated for use in motor vehicles, the composition and 

properties of which do not meet the requirements of the 

reformulated gasoline regulations promulgated by the U.S. 

Environmental Protection Agency under 40 CFR 80.40 or the 

summer RVP standards required under 40 CFR 80.27 or as 

specified by the state. Note: This category excludes 

conventional blendstock for oxygenate blending (CBOB) as 

well as other blendstock. 

Crude oil means a mixture of hydrocarbons that exists 

in liquid phase in natural underground reservoirs and 

Deleted: the 

Deleted: the 
56

remains liquid at atmospheric pressure after passing 

through surface separating facilities. Depending upon the 

characteristics of the crude stream, it may also include 

any of the following: 

(1) Small amounts of hydrocarbons that exist in 

gaseous phase in natural underground reservoirs but are 

liquid at atmospheric pressure after being recovered from 

oil well (casinghead) gas in lease separators and are 

subsequently commingled with the crude stream without being 

separately measured. Lease condensate recovered as a liquid 

from natural gas wells in lease or field separation 

facilities and later mixed into the crude stream is also 

included. 

(2) Small amounts of nonhydrocarbons produced from 

oil, such as sulfur and various metals. 

(3) Drip gases, and liquid hydrocarbons produced from 

tar sands, oil sands, gilsonite, and oil shale. Liquids 

produced at natural gas processing plants are excluded. 

Crude oil is refined to produce a wide array of petroleum 

products, including heating oils; gasoline, diesel and jet 

fuels; lubricants; asphalt; ethane, propane, and butane; 

and many other products used for their energy or chemical 

content.
57

Daily spread means a manure management system 

component in which manure is routinely removed from a 

confinement facility and is applied to cropland or pasture 

within 24 hours of excretion. 

Day means any consistently designated 24 hour period 

during which an emission unit is operated. 

Decarburization vessel means any vessel used to 

further refine molten steel to reduce the carbon content of 

the steel. This definition includes vessels used for 

argon-oxygen decarburization, vacuum degassers, vacuum 

oxygen degassers, Rheinstahl-Heraus systems, and other 

decarburization vessels.

Degradable organic carbon (DOC) means the fraction of 

the total mass of a waste material that can be biologically 

degraded. 

Delayed coking unit means one or more refinery process 

units in which high molecular weight petroleum derivatives 

are thermally cracked and petroleum coke is produced in a 

series of closed, batch system reactors. A delayed coking 

unit consists of the coke drums and ancillary equipment 

associated with a single fractionator. 

Density means the mass contained in a given unit 

volume (mass/volume). 
58

Destruction means, with respect to landfills and 

manure management, the combustion of methane in any on-site 

or off-site combustion technology. Destroyed methane 

includes, but is not limited to, methane combusted by 

flaring, methane destroyed by thermal oxidation, methane 

combusted for use in on-site energy or heat production 

technologies, methane that is conveyed through pipelines 

(including natural gas pipelines) for off-site combustion, 

and methane that is collected for any other on-site or offsite use as a fuel. 

Destruction means, with respect to fluorinated GHGs, 

the expiration of a fluorinated GHG to the destruction 

efficiency actually achieved. Such destruction does not 

result in a commercially useful end product. 

Destruction Efficiency means the efficiency with which 

a destruction device reduces the GWP-weighted mass of 

greenhouse gases fed into the device, considering the GWPweighted masses of both the greenhouse gases fed into the 

device and those exhausted from the device. The 

Destruction Efficiency is expressed in Equation A-2 of this 

section: 

IN

OUT

tCO e

tCO e

DE

2

2

= 1− (Eq. A-2) 

Where: 
59

DE = Destruction Efficiency 

tCO2eIN = The GWP-weighted mass of GHGs fed into the 

destruction device 

tCO2eOUT = The GWP-weighted mass of GHGs exhausted from 

the destruction device, including GHGs formed 

during the destruction process 

Destruction efficiency, or flaring destruction 

efficiency, refers to the fraction of the gas that leaves 

the flare partially or fully oxidized. 

Diesel–Other is any distillate fuel oil not defined 

elsewhere, including Diesel Treated as Blendstock (DTAB). 

DIPE (diisopropyl ether, (CH3)2CHOCH(CH3)2) is an ether 

as described in "Oxygenates." 

Direct liquefaction means the conversion of coal 

directly into liquids, rather than passing through an 

intermediate gaseous state. 

Direct reduction furnace means a high temperature 

furnace typically fired with natural gas to produce solid 

iron from iron ore or iron ore pellets and coke, coal, or 

other carbonaceous materials. 

Distillate Fuel Oil means a classification for one of 

the petroleum fractions produced in conventional 

distillation operations and from crackers and hydrotreating 

process units. The generic term distillate fuel oil 

includes kerosene, diesel fuels (Diesel Fuels No. 1, No. 2, 
60

and No. 4), and fuel oils (Fuel Oils No. 1, No. 2, and No. 

4). 

Distillate Fuel No. 1 has a maximum distillation 

temperature of 550 °F at the 90 percent recovery point and 

a minimum flash point of 100 °F and includes fuels commonly 

known as Diesel Fuel No. 1 and Fuel Oil No. 1, but excludes 

kerosene. This fuel is further subdivided into categories 

of sulfur content: High Sulfur (greater than 500 ppm), Low 

Sulfur (less than or equal to 500 ppm and greater than 15 

ppm), and Ultra Low Sulfur (less than or equal to 15 ppm). 

Distillate Fuel No. 2 has a minimum and maximum 

distillation temperature of 540 °F and 640 °F at the 90 

percent recovery point, respectively, and includes fuels 

commonly known as Diesel Fuel No. 2 and Fuel Oil No. 2. 

This fuel is further subdivided into categories of sulfur 

content: High Sulfur (greater than 500 ppm), Low Sulfur 

(less than or equal to 500 ppm and greater than 15 ppm), 

and Ultra Low Sulfur (less than or equal to 15 ppm). 

Distillate Fuel No. 4 is a distillate fuel oil made by 

blending distillate fuel oil and residual fuel oil, with a 

minimum flash point of 131 °F. 

DOCf means the fraction of DOC that actually decomposes 

under the (presumably anaerobic) conditions within the 

landfill. 
61

Dry lot means a manure management system component 

consisting of a paved or unpaved open confinement area 

without any significant vegetative cover where accumulating 

manure may be removed periodically. 

Electric arc furnace (EAF) means a furnace that 

produces molten alloy metal and heats the charge materials 

with electric arcs from carbon electrodes. 

Electric arc furnace steelmaking means the production 

of carbon, alloy, or specialty steels using an EAF. This 

definition excludes EAFs at steel foundries and EAFs used 

to produce nonferrous metals. 

Electrothermic furnace means a furnace that heats the 

charged materials with electric arcs from carbon 

electrodes. 

Emergency generator means a stationary combustion 

device, such as a reciprocating internal combustion engine 

or turbine that serves solely as a secondary source of 

mechanical or electrical power whenever the primary energy 

supply is disrupted or discontinued during power outages or 

natural disasters that are beyond the control of the owner 

or operator of a facility. An emergency generator operates 

only during emergency situations, for training of personnel 

under simulated emergency conditions, as part of emergency 

demand response procedures, or for standard performance 
62

testing procedures as required by law or by the generator 

manufacturer. A generator that serves as a back-up power 

source under conditions of load shedding, peak shaving, 

power interruptions pursuant to an interruptible power 

service agreement, or scheduled facility maintenance shall 

not be considered an emergency generator. 

Emergency equipment means any auxiliary fossil fuelpowered equipment, such as a fire pump, that is used only 

in emergency situations. 

ETBE (ethyl tertiary butyl ether, (CH3)3COC2H) is an 

ether as described in "Oxygenates." 

Ethane is a paraffinic hydrocarbon with molecular 

formula C2H6. 

Ethanol is an anhydrous alcohol with molecular formula 

C2H5OH. 

Ethylene is an olefinic hydrocarbon with molecular 

formula C2H4. 

Ex refinery gate means the point at which a petroleum 

product leaves the refinery. 

Experimental furnace means a glass melting furnace 

with the sole purpose of operating to evaluate glass 

melting processes, technologies, or glass products. An 

experimental furnace does not produce glass that is sold 

(except for further research and development purposes) or 
63

that is used as a raw material for non-experimental 

furnaces. 

Export means to transport a product from inside the 

United States to persons outside the United States, 

excluding any such transport on behalf of the United States 

military including foreign military sales under the Arms 

Export Control Act. 

Exporter means any person, company or organization of 

record that transfers for sale or for other benefit, 

domestic products from the United States to another country 

or to an affiliate in another country, excluding any such 

transfers on behalf of the United States military or 

military purposes including foreign military sales under 

the Arms Export Control Act. An exporter is not the entity 

merely transporting the domestic products, rather an 

exporter is the entity deriving the principal benefit from 

the transaction. 

Facility means any physical property, plant, building, 

structure, source, or stationary equipment located on one 

or more contiguous or adjacent properties in actual 

physical contact or separated solely by a public roadway or 

other public right-of-way and under common ownership or 

common control, that emits or may emit any greenhouse gas. 

Operators of military installations may classify such 
64

installations as more than a single facility based on 

distinct and independent functional groupings within 

contiguous military properties. 

Feed means the prepared and mixed materials, which 

include but are not limited to materials such as limestone, 

clay, shale, sand, iron ore, mill scale, cement kiln dust 

and flyash, that are fed to the kiln. Feed does not 

include the fuels used in the kiln to produce heat to form 

the clinker product. 

Feedstock means raw material inputs to a process that 

are transformed by reaction, oxidation, or other chemical 

or physical methods into products and by-products. 

Supplemental fuel burned to provide heat or thermal energy 

is not a feedstock. 

Fischer-Tropsch process means a catalyzed chemical 

reaction in which synthesis gas, a mixture of carbon 

monoxide and hydrogen, is converted into liquid 

hydrocarbons of various forms. 

Flare means a combustion device, whether at ground 

level or elevated, that uses an open flame to burn 

combustible gases with combustion air provided by 

uncontrolled ambient air around the flame. 
65

Flat glass means glass made of soda-lime recipe and 

produced into continuous flat sheets and other products 

listed in NAICS 327211. 

Flowmeter means a device that measures the mass or 

volumetric rate of flow of a gas, liquid, or solid moving 

through an open or closed conduit (e.g. flowmeters include, 

but are not limited to, rotameters, turbine meters, 

coriolis meters, orifice meters, ultra-sonic flowmeters, 

and vortex flowmeters). 

Fluid coking unit means one or more refinery process 

units in which high molecular weight petroleum derivatives 

are thermally cracked and petroleum coke is continuously 

produced in a fluidized bed system. The fluid coking unit 

includes equipment for controlling air pollutant emissions 

and for heat recovery on the fluid coking burner exhaust 

vent. There are two basic types of fluid coking units: a 

traditional fluid coking unit in which only a small portion 

of the coke produced in the unit is burned to fuel the unit 

and the fluid coking burner exhaust vent is directed to the 

atmosphere (after processing in a CO boiler or other air 

pollutant control equipment) and a flexicoking unit in 

which an auxiliary burner is used to partially combust a 

significant portion of the produced petroleum coke to 
66

generate a low value fuel gas that is used as fuel in other 

combustion sources at the refinery. 

Fluorinated greenhouse gas means sulfur hexafluoride 

(SF6), nitrogen trifluoride (NF3), and any fluorocarbon 

except for controlled substances as defined at 40 CFR part 

82, subpart A and substances with vapor pressures of less 

than 1 mm of Hg absolute at 25 degrees C. With these 

exceptions, “fluorinated GHG” includes but is not limited 

to any hydrofluorocarbon, any perfluorocarbon, any fully 

fluorinated linear, branched or cyclic alkane, ether, 

tertiary amine or aminoether, any perfluoropolyether, and 

any hydrofluoropolyether. 

Fossil fuel means natural gas, petroleum, coal, or any 

form of solid, liquid, or gaseous fuel derived from such 

material, including for example, consumer products that are 

derived from such materials and are combusted. 

Fossil fuel-fired means powered by combustion of 

fossil fuel, alone or in combination with any other fuel, 

regardless of the percentage of fossil fuel consumed. 

Fractionators means plants that produce fractionated 

natural gas liquids (NGLs) extracted from produced natural 

gas and separate the NGLs individual component products: 

ethane, propane, butanes and pentane-plus (C5+). Plants 

that only process natural gas but do not fractionate NGLs 
67

further into component products are not considered 

fractionators. Some fractionators do not process 

production gas, but instead fractionate bulk NGLs received 

from natural gas processors. Some fractionators both 

process natural gas and fractionate bulk NGLs received from 

other plants. 

Fuel means solid, liquid or gaseous combustible 

material. 

Fuel gas means gas generated at a petroleum refinery, 

petrochemical plant, or similar industrial process unit, 

and that is combusted separately or in any combination with 

any type of gas. 

Fuel gas system means a system of compressors, piping, 

knock-out pots, mix drums, and, if necessary, units used to 

remove sulfur contaminants from the fuel gas (e.g., amine 

scrubbers) that collects fuel gas from one or more sources 

for treatment, as necessary, and transport to a stationary 

combustion unit. A fuel gas system may have an 

overpressure vent to a flare but the primary purpose for a 

fuel gas system is to provide fuel to the various 

combustion units at the refinery or petrochemical plant. 

Gas collection system or landfill gas collection 

system means a system of pipes used to collect landfill gas 

from different locations in the landfill by means of a fan 
68

or similar mechanical draft equipment to a single location 

for treatment (thermal destruction) or use. Landfill gas 

collection systems may also include knock-out or separator 

drums and/or a compressor.

Landfill gas collection systems do not include 

“passive” systems, whereby landfill gas flows naturally to 

the surface of the landfill where an opening or pipe (vent) 

is installed to allow for natural gas flow.

Gas-fired unit means a stationary combustion unit that 

derives more than 50 percent of its annual heat input from 

the combustion of gaseous fuels, and the remainder of its 

annual heat input from the combustion of fuel oil or other 

liquid fuels. 

Gas monitor means an instrument that continuously 

measures the concentration of a particular gaseous species 

in the effluent of a stationary source. 

Gaseous fuel means a material that is in the gaseous 

state at standard atmospheric temperature and pressure 

conditions and that is combusted to produce heat and/or 

energy. 

Gasification means the conversion of a solid or liquid 

raw material into a gas. 

Gasoline – Other is any gasoline that is not defined 

elsewhere, including GTAB (gasoline treated as blendstock). 
69

Glass melting furnace means a unit comprising a 

refractory-lined vessel in which raw materials are charged 

and melted at high temperature to produce molten glass. 

Glass produced means the weight of glass exiting a 

glass melting furnace. 

Global warming potential or GWP means the ratio of the 

time-integrated radiative forcing from the instantaneous 

release of one kilogram of a trace substance relative to 

that of one kilogram- of a reference gas, i.e., CO2. 

GPA means the Gas Processors Association. 

Greenhouse gas or GHG means carbon dioxide (CO2), 

methane (CH4), nitrous oxide (N2O), sulfur hexafluoride 

(SF6), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), 

and other fluorinated greenhouse gases as defined in this 

section. 

GTBA (gasoline-grade tertiary butyl alcohol, 

(CH3)3COH), or t-butanol, is an alcohol as described in 

"Oxygenates." 

Heavy Gas Oils are petroleum distillates with an 

approximate boiling range from 651 °F to 1,000 °F. 

Heel means the amount of gas that remains in a 

shipping container after it is discharged or off-loaded 

(that is no more than ten percent of the volume of the 

container). 
70

High heat value or HHV means the high or gross heat 

content of the fuel with the heat of vaporization included. 

The water is assumed to be in a liquid state. 

Hydrofluorocarbons or HFCs means a class of GHGs 

consisting of hydrogen, fluorine, and carbon. 

Import means, to land on, bring into, or introduce 

into, any place subject to the jurisdiction of the United 

States whether or not such landing, bringing, or 

introduction constitutes an importation within the meaning 

of the customs laws of the United States, with the 

following exemptions: 

(1) Off-loading used or excess fluorinated GHGs or 

nitrous oxide of U.S. origin from a ship during servicing. 

(2) Bringing fluorinated GHGs or nitrous oxide into 

the U.S. from Mexico where the fluorinated GHGs or nitrous 

oxide had been admitted into Mexico in bond and were of 

U.S. origin. 

(3) Bringing fluorinated GHGs or nitrous oxide into 

the U.S. when transported in a consignment of personal or 

household effects or in a similar non-commercial situation 

normally exempted from U.S. Customs attention. 

(4) Bringing fluorinated GHGs or nitrous into U.S. 

jurisdiction exclusively for U. S. military purposes. 
71

Importer means any person, company, or organization of 

record that for any reason brings a product into the United 

States from a foreign country, excluding introduction into 

U.S. jurisdiction exclusively for United States military 

purposes. An importer is the person, company, or 

organization primarily liable for the payment of any duties 

on the merchandise or an authorized agent acting on their 

behalf. The term includes, as appropriate: 

(1) The consignee. 

(2) The importer of record. 

(3) The actual owner. 

(4) The transferee, if the right to draw merchandise 

in a bonded warehouse has been transferred. 

Indurating furnace means a furnace where unfired 

taconite pellets, called green balls, are hardened at high 

temperatures to produce fired pellets for use in a blast 

furnace. Types of indurating furnaces include straight 

gate and grate kiln furnaces. 

Industrial greenhouse gases means nitrous oxide or any 

fluorinated greenhouse gas. 

In-line kiln/raw mill means a system in a portland 

cement production process where a dry kiln system is 

integrated with the raw mill so that all or a portion of 

the kiln exhaust gases are used to perform the drying 
72

operation of the raw mill, with no auxiliary heat source 

used. In this system the kiln is capable of operating 

without the raw mill operating, but the raw mill cannot 

operate without the kiln gases, and consequently, the raw 

mill does not generate a separate exhaust gas stream. 

Isobutane is a paraffinic branch chain hydrocarbon 

with molecular formula C4H10. 

Isobutylene is an olefinic branch chain hydrocarbon 

with molecular formula C4H8. 

Kerosene is a light petroleum distillate with a 

maximum distillation temperature of 400 °F at the 10-

percent recovery point, a final maximum boiling point of 

572 °F, a minimum flash point of 100 °F, and a maximum 

freezing point of -22 °F. Included are No. 1-K and No. 2-K, 

distinguished by maximum sulfur content (0.04 and 0.30 

percent of total mass, respectively), as well as all other 

grades of kerosene called range or stove oil. Excluded is 

kerosene-type jet fuel (see definition herein). 

Kerosene-Type Jet Fuel means a kerosene-based product 

used in commercial and military turbojet and turboprop 

aircraft. The product has a maximum distillation 

temperature of 400 °F at the 10 percent recovery point and 

a final maximum boiling point of 572 °F. Included are Jet 

A, Jet A-1, JP-5, and JP-8. 
73

Kiln means an oven, furnace, or heated enclosure used 

for thermally processing a mineral or mineral-based 

substance. 

Landfill means an area of land or an excavation in 

which wastes are placed for permanent disposal and that is 

not a land application unit, surface impoundment, injection 

well, or waste pile as those terms are defined under 40 CFR 

257.2. 

Landfill gas means gas produced as a result of 

anaerobic decomposition of waste materials in the landfill. 

Landfill gas generally contains 40 to 60 percent methane on 

a dry basis, typically less than 1 percent non-methane 

organic chemicals, and the remainder being carbon dioxide. 

Lime is the generic term for a variety of chemical 

compounds that are produced by the calcination of limestone 

or dolomite. These products include but are not limited to 

calcium oxide, high-calcium quicklime, calcium hydroxide, 

hydrated lime, dolomitic quicklime, and dolomitic hydrate. 

Liquid/Slurry means a manure management component in 

which manure is stored as excreted or with some minimal 

addition of water to facilitate handling and is stored in 

either tanks or earthen ponds, usually for periods less 

than one year. 
74

Lubricants include all grades of lubricating oils, 

from spindle oil to cylinder oil to those used in greases. 

Petroleum lubricants may be produced from distillates or 

residues. 

Makeup chemicals means carbonate chemicals (e.g., 

sodium and calcium carbonates) that are added to the 

chemical recovery areas of chemical pulp mills to replace 

chemicals lost in the process. 

Manure composting means the biological oxidation of a 

solid waste including manure usually with bedding or 

another organic carbon source typically at thermophilic 

temperatures produced by microbial heat production. There 

are four types of composting employed for manure 

management: static, in vessel, intensive windrow and 

passive windrow. Static composting typically occurs in an 

enclosed channel, with forced aeration and continuous 

mixing. In vessel composting occurs in piles with forced 

aeration but no mixing. Intensive windrow composting occurs 

in windrows with regular turning for mixing and aeration. 

Passive windrow composting occurs in windrows with 

infrequent turning for mixing and aeration. 

Maximum rated heat input capacity means the hourly 

heat input to a unit (in mmBtu/hr), when it combusts the 

maximum amount of fuel per hour that it is capable of 
75

combusting on a steady state basis, as of the initial 

installation of the unit, as specified by the manufacturer. 

Maximum rated input capacity means the maximum 

charging rate of a municipal waste combustor unit expressed 

in tons per day of municipal solid waste combusted, 

calculated according to the procedures under 40 CFR 

60.58b(j). 

Mcf means thousand cubic feet. 

Methane conversion factor means the extent to which 

the CH4 producing capacity (Bo) is realized in each type of 

treatment and discharge pathway and system. Thus, it is an 

indication of the degree to which the system is anaerobic. 

Methane correction factor means an adjustment factor 

applied to the methane generation rate to account for 

portions of the landfill that remain aerobic. The methane 

correction factor can be considered the fraction of the 

total landfill waste volume that is ultimately disposed of 

in an anaerobic state. Managed landfills that have soil or 

other cover materials have a methane correction factor of 

1. 

Methanol (CH3OH) is an alcohol as described in 

"Oxygenates." 

Midgrade gasoline has an octane rating greater than or 

equal to 88 and less than or equal to 90. This definition 
76

applies to the midgrade categories of Conventional-Summer, 

Conventional-Winter, Reformulated-Summer, and ReformulatedWinter. For midgrade categories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOB-Winter, this definition 

refers to the expected octane rating of the finished 

gasoline after oxygenate has been added to the RBOB or 

CBOB. 

Miscellaneous Products include all refined petroleum 

products not defined elsewhere. It includes, but is not 

limited to, naphtha-type jet fuel (Jet B and JP-4), 

petrolatum lube refining by-products (aromatic extracts and 

tars), absorption oils, ram-jet fuel, petroleum rocket 

fuels, synthetic natural gas feedstocks, waste feedstocks, 

and specialty oils. It excludes organic waste sludges, tank 

bottoms, spent catalysts, and sulfuric acid. 

MMBtu means million British thermal units. 

Motor gasoline (finished) means a complex mixture of 

volatile hydrocarbons, with or without additives, suitably 

blended to be used in spark ignition engines. Motor 

gasoline includes conventional gasoline, reformulated 

gasoline, and all types of oxygenated gasoline. Gasoline 

also has seasonal variations in an effort to control ozone 

levels. This is achieved by lowering the Reid Vapor 

Pressure (RVP) of gasoline during the summer driving 
77

season. Depending on the region of the country the RVP is 

lowered to below 9.0 psi or 7.8 psi. The RVP may be further 

lowered by state regulations. 

Mscf means thousand standard cubic feet. 

MTBE (methyl tertiary butyl ether, (CH3)3COCH3) is an 

ether as described in "Oxygenates." 

Municipal solid waste landfill or MSW landfill means 

an entire disposal facility in a contiguous geographical 

space where household waste is placed in or on land. An 

MSW landfill may also receive other types of RCRA Subtitle 

D wastes (40 CFR 257.2) such as commercial solid waste, 

nonhazardous sludge, conditionally exempt small quantity 

generator waste, and industrial solid waste. Portions of 

an MSW landfill may be separated by access roads, public 

roadways, or other public right-of-ways. An MSW landfill 

may be publicly or privately owned. 

Municipal solid waste or MSW means solid phase 

household, commercial/retail, and/or institutional waste, 

such as, but not limited to, yard waste and refuse. 

N2O means nitrous oxide. 

Naphthas (< 401 °F) is a generic term applied to a 

petroleum fraction with an approximate boiling range 

between 122 °F and 400 °F. The naphtha fraction of crude 

Deleted: million 
78

oil is the raw material for gasoline and is composed 

largely of paraffinic hydrocarbons. 

Natural gas means a naturally occurring mixture of 

hydrocarbon and non-hydrocarbon gases found in geologic 

formations beneath the earth’s surface, of which its 

constituents include, but are not limited to, methane, 

heavier hydrocarbons and carbon dioxide. Natural gas may 

be field quality (which varies widely) or pipeline quality. 

For the purposes of this subpart, the definition of natural 

gas includes similarly constituted fuels such as field 

production gas, process gas, and fuel gas. 

Natural Gas Liquids (NGLs) means those hydrocarbons in 

natural gas that are separated from the gas as liquids 

through the process of absorption, condensation, 

adsorption, or other methods at lease separators and field 

facilities. Generally, such liquids consist of ethane, 

propane, butanes, and pentanes plus. Bulk NGLs refers to 

mixtures of NGLs that are sold or delivered as 

undifferentiated product from natural gas processing 

plants. 

Natural gasoline means a mixture of liquid 

hydrocarbons (mostly pentanes and heavier hydrocarbons) 

extracted from natural gas. It includes isopentane. 
79

NIST means the United States National Institute of 

Standards and Technology. 

Nitric acid production line means a series of reactors 

and absorbers used to produce nitric acid. 

Nitrogen excreted is the nitrogen that is excreted by 

livestock in manure and urine. 

Non-crude feedstocks means any petroleum product or 

natural gas liquid that enters the refinery to be further 

refined or otherwise used on site, including supplemental 

fuel burned to provide heat or thermal energy. 

Non-recovery coke oven battery means a group of ovens 

connected by common walls and operated as a unit, where 

coal undergoes destructive distillation under negative 

pressure to produce coke, and which is designed for the 

combustion of the coke oven gas from which by-products are 

not recovered. 

Oil-fired unit means a stationary combustion unit that 

derives more than 50 percent of its annual heat input from 

the combustion of fuel oil, and the remainder of its annual 

heat input from the combustion of natural gas or other 

gaseous fuels. 

Open-ended valve or Lines (OELs) means any valve, 

except pressure relief valves, having one side of the valve 

Deleted: as a feedstock 
80

seat in contact with process fluid and one side open to 

atmosphere, either directly or through open piping. 

Operating hours means the duration of time in which a 

process or process unit is utilized; this excludes 

shutdown, maintenance, and standby. 

Operational change means, for purposes of §98.3(b), a 

change in the type of feedstock or fuel used, a change in 

operating hours, or a change in process production rate. 

Operator means any person who operates or supervises a 

facility or supplier. 

Other Oils (> 401 °F) are oils with a boiling range 

equal to or greater than 401 °F that are generally intended 

for use as a petrochemical feedstock and are not defined 

elsewhere. 

Owner means any person who has legal or equitable 

title to, has a leasehold interest in, or control of a 

facility or supplier, except a person whose legal or 

equitable title to or leasehold interest in the facility or 

supplier arises solely because the person is a limited 

partner in a partnership that has legal or equitable title 

to, has a leasehold interest in, or control of the facility 

or supplier shall not be considered an “owner” of the 

facility or supplier. 
81

Oxygenates means substances which, when added to 

gasoline, increase the oxygen content of the gasoline. 

Common oxygenates are ethanol, methyl tertiary butyl ether 

(MTBE), ethyl tertiary butyl ether (ETBE), tertiary amyl 

methyl ether (TAME), diisopropyl ether (DIPE), and 

methanol. 

Pasture/Range/Paddock means the manure from pasture 

and range grazing animals is allowed to lie as deposited, 

and is not managed. 

Pentanes Plus, or C5+, is a mixture of hydrocarbons 

that is a liquid at ambient temperature and pressure, and 

consists mostly of pentanes (five carbon chain) and higher 

carbon number hydrocarbons. Pentanes plus includes, but is 

not limited to, normal pentane, isopentane, hexanes-plus 

(natural gasoline), and plant condensate. 

Perfluorocarbons or PFCs means a class of greenhouse 

gases consisting on the molecular level of carbon and 

fluorine. 

Petrochemical means methanol, acrylonitrile, ethylene, 

ethylene oxide, ethylene dichloride, and any form of carbon 

black. 

Petrochemical Feedstocks means feedstocks derived from 

petroleum for the manufacture of chemicals, synthetic 

rubber, and a variety of plastics. This category is 
82

usually divided into naphthas less than 401 °F and other 

oils greater than 401 °F. 

Petroleum means oil removed from the earth and the oil 

derived from tar sands and shale. 

Petroleum coke means a black solid residue, obtained 

mainly by cracking and carbonizing of petroleum derived 

feedstocks, vacuum bottoms, tar and pitches in processes 

such as delayed coking or fluid coking. It consists mainly 

of carbon (90 to 95 percent), has low ash content, and may 

be used as a feedstock in coke ovens. This product is also 

known as marketable coke or catalyst coke. 

Petroleum product means all refined and semi-refined 

products that are produced at a refinery by processing 

crude oil and other petroleum-based feedstocks, including 

petroleum products derived from co-processing biomass and 

petroleum feedstock together, but not including plastics or 

plastic products. Petroleum products may be combusted for 

energy use, or they may be used either for non-energy 

processes or as non-energy products. The definition of 

petroleum product for importers and exporters excludes 

waxes. 

Pit storage below animal confinement (deep pits) means 

the collection and storage of manure typically below a 

slatted floor in an enclosed animal confinement facility. 
83

This usually occurs with little or no added water for 

periods less than one year. 

Portable means designed and capable of being carried 

or moved from one location to another. Indications of 

portability include but are not limited to wheels, skids, 

carrying handles, dolly, trailer, or platform. Equipment is 

not portable if any one of the following conditions exists: 

(1) The equipment is attached to a foundation. 

(2) The equipment or a replacement resides at the 

same location for more than 12 consecutive months. 

(3) The equipment is located at a seasonal facility 

and operates during the full annual operating period of the 

seasonal facility, remains at the facility for at least two 

years, and operates at that facility for at least three 

months each year. 

(4) The equipment is moved from one location to 

another in an attempt to circumvent the portable residence 

time requirements of this definition. 

Poultry manure with litter means a manure management 

system component that is similar to cattle and swine deep 

bedding except usually not combined with a dry lot or 

pasture. The system is typically used for poultry breeder 

flocks and for the production of meat type chickens 

(broiler) and other fowl. 
84

Poultry manure without litter means a manure 

management system component that may manage manure in a 

liquid form, similar to open pits in enclosed animal 

confinement facilities. These systems may alternatively be 

designed and operated to dry manure as it accumulates. The 

latter is known as a high-rise manure management system and 

is a form of passive windrow manure composting when 

designed and operated properly. 

Precision of a measurement at a specified level(e.g., 

one percent of full scale or one percent of the value 

measured) means that 95 percent of repeat measurements made 

by a device or technique are within the range bounded by 

the mean of the measurements plus or minus the specified 

level. 

Premium grade gasoline is gasoline having an antiknock 

index, i.e., octane rating, greater than 90. This 

definition applies to the premium grade categories of 

Conventional-Summer, Conventional-Winter, ReformulatedSummer, and Reformulated-Winter. For premium grade 

categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and 

CBOB-Winter, this definition refers to the expected octane 

rating of the finished gasoline after oxygenate has been 

added to the RBOB or CBOB. 
85

Pressed and blown glass means glass which is pressed, 

blown, or both, into products such as light bulbs, glass 

fiber, technical glass, and other products listed in NAICS 

327212. 

Pressure relief device or pressure relief valve or 

pressure safety valve means a safety device used to prevent 

operating pressures from exceeding the maximum allowable 

working pressure of the process equipment. A common 

pressure relief device is but not limited to a springloaded pressure relief valve. Devices that are actuated 

either by a pressure of less than or equal to 2.5 psig or 

by a vacuum are not pressure relief devices. 

Process emissions means the emissions from industrial 

processes (e.g., cement production, ammonia production) 

involving chemical or physical transformations other than 

fuel combustion. For example, the calcination of 

carbonates in a kiln during cement production or the 

oxidation of methane in an ammonia process results in the 

release of process CO2 emissions to the atmosphere. 

Emissions from fuel combustion to provide process heat are 

not part of process emissions, whether the combustion is 

internal or external to the process equipment. 

Process unit means the equipment assembled and 

connected by pipes and ducts to process raw materials and 
86

to manufacture either a final product or an intermediate 

used in the onsite production of other products. The 

process unit also includes the purification of recovered 

byproducts. 

Process vent means means a gas stream that: (1) is 

discharged through a conveyance to the atmosphere either 

directly or after passing through a control device; (2) 

originates from a unit operation, including but not limited 

to reactors (including reformers, crackers, and furnaces, 

and separation equipment for products and recovered 

byproducts); and (3) contains or has the potential to 

contain GHG that is generated in the process. Process vent 

does not include safety device discharges, equipment leaks, 

gas streams routed to a fuel gas system or to a flare, 

discharges from storage tanks. 

Propane is a paraffinic hydrocarbon with molecular 

formula C3H8. 

Propylene is an olefinic hydrocarbon with molecular 

formula C3H6. 

Pulp mill lime kiln means the combustion units (e.g., 

rotary lime kiln or fluidized bed calciner) used at a kraft 

or soda pulp mill to calcine lime mud, which consists 

primarily of calcium carbonate, into quicklime, which is 

calcium oxide. 
87

Pushing means the process of removing the coke from 

the coke oven at the end of the coking cycle. Pushing 

begins when coke first begins to fall from the oven into 

the quench car and ends when the quench car enters the 

quench tower. 

Raw mill means a ball and tube mill, vertical roller 

mill or other size reduction equipment, that is not part of 

an in-line kiln/raw mill, used to grind feed to the 

appropriate size. Moisture may be added or removed from 

the feed during the grinding operation. If the raw mill is 

used to remove moisture from feed materials, it is also, by 

definition, a raw material dryer. The raw mill also 

includes the air separator associated with the raw mill. 

RBOB-Summer (reformulated blendstock for oxygenate 

blending) means a petroleum product which, when blended 

with a specified type and percentage of oxygenate, meets 

the definition of Reformulated-Summer. 

RBOB-Winter (reformulated blendstock for oxygenate 

blending) means a petroleum product which, when blended 

with a specified type and percentage of oxygenate, meets 

the definition of Reformulated-Winter. 

Reformulated—Summer refers to finished gasoline 

formulated for use in motor vehicles, the composition and 

properties of which meet the requirements of the 
88

reformulated gasoline regulations promulgated by the U.S. 

Environmental Protection Agency under 40 CFR 80.40 and 40 

CFR 80.41, and summer RVP standards required under 40 CFR 

80.27 or as specified by the state. Reformulated gasoline 

excludes Reformulated Blendstock for Oxygenate Blending 

(RBOB) as well as other blendstock. 

Reformulated—Winter refers to finished gasoline 

formulated for use in motor vehicles, the composition and 

properties of which meet the requirements of the 

reformulated gasoline regulations promulgated by the U.S. 

Environmental Protection Agency under 40 CFR 80.40 and 40 

CFR 80.41, but which do not meet summer RVP standards 

required under 40 CFR 80.27 or as specified by the state. 

Note: This category includes Oxygenated Fuels Program 

Reformulated Gasoline (OPRG). Reformulated gasoline 

excludes Reformulated Blendstock for Oxygenate Blending 

(RBOB) as well as other blendstock. 

Regular grade gasoline is gasoline having an 

antiknock index, i.e., octane rating, greater than or equal 

to 85 and less than 88. This definition applies to the 

regular grade categories of Conventional-Summer, 

Conventional-Winter, Reformulated-Summer, and ReformulatedWinter. For regular grade categories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOB-Winter, this definition 
89

refers to the expected octane rating of the finished 

gasoline after oxygenate has been added to the RBOB or 

CBOB. 

Rendered animal fat, or tallow, means fats extracted 

from animals which are generally used as a feedstock in 

making biodiesel. 

Research and development means those activities 

conducted in process units or at laboratory bench-scale 

settings whose purpose is to conduct research and 

development for new processes, technologies, or products 

and whose purpose is not for the manufacture of products 

for commercial sale, except in a de minimis manner. 

Residual Fuel Oil No. 5 (Navy Special) is a 

classification for the heavier fuel oil generally used in 

steam powered vessels in government service and inshore 

power plants. It has a minimum flash point of 131 °F. 

Residual Fuel Oil No. 6 (a.k.a. Bunker C) is a 

classification for the heavier fuel oil generally used for 

the production of electric power, space heating, vessel 

bunkering and various industrial purposes. It has a minimum 

flash point of 140 °F. 

Residuum is residue from crude oil after distilling 

off all but the heaviest components, with a boiling range 

greater than 1,000 °F. 
90

Road Oil is any heavy petroleum oil, including 

residual asphaltic oil used as a dust palliative and 

surface treatment on roads and highways. It is generally 

produced in six grades, from 0, the most liquid, to 5, the 

most viscous. 

Rotary lime kiln means a unit with an inclined 

rotating drum that is used to produce a lime product from 

limestone by calcination. 

Safety device means a closure device such as a 

pressure relief valve, frangible disc, fusible plug, or any 

other type of device which functions exclusively to prevent 

physical damage or permanent deformation to a unit or its 

air emission control equipment by venting gases or vapors 

directly to the atmosphere during unsafe conditions 

resulting from an unplanned, accidental, or emergency 

event. A safety device is not used for routine venting of 

gases or vapors from the vapor headspace underneath a cover 

such as during filling of the unit or to adjust the 

pressure in response to normal daily diurnal ambient 

temperature fluctuations. A safety device is designed to 

remain in a closed position during normal operations and 

open only when the internal pressure, or another relevant 

parameter, exceeds the device threshold setting applicable 

to the air emission control equipment as determined by the 
91

owner or operator based on manufacturer recommendations, 

applicable regulations, fire protection and prevention 

codes and practices, or other requirements for the safe 

handling of flammable, combustible, explosive, reactive, or 

hazardous materials. 

Semi-refined petroleum product means all oils 

requiring further processing. Included in this category 

are unfinished oils which are produced by the partial 

refining of crude oil and include the following: naphthas 

and lighter oils; kerosene and light gas oils; heavy gas 

oils; and residuum, and all products that require further 

processing or the addition of blendstocks. 

Sendout means, in the context of a local distribution 

company, the total deliveries of natural gas to customers 

over a specified time interval (typically hour, day, month, 

or year). Sendout is the sum of gas received through the 

city gate, gas withdrawn from on-system storage or peak 

shaving plants, and gas produced and delivered into the 

distribution system; and is net of any natural gas injected 

into on-system storage. It comprises gas sales, exchange, 

deliveries, gas used by company, and unaccounted for gas. 

Sendout is measured at the city gate station, and other onsystem receipt points from storage, peak shaving, and 

production. 
92

Sensor means a device that measures a physical 

quantity/quality or the change in a physical 

quantity/quality, such as temperature, pressure, flow rate, 

pH, or liquid level. 

SF6 means sulfur hexafluoride. 

Shutdown means the cessation of operation of an 

emission source for any purpose. 

Silicon carbide means an artificial abrasive produced 

from silica sand or quartz and petroleum coke. 

Sinter process means a process that produces a fused 

aggregate of fine iron-bearing materials suited for use in 

a blast furnace. The sinter machine is composed of a 

continuous traveling grate that conveys a bed of ore fines 

and other finely divided iron-bearing material and fuel 

(typically coke breeze), a burner at the feed end of the 

grate for ignition, and a series of downdraft windboxes 

along the length of the strand to support downdraft 

combustion and heat sufficient to produce a fused sinter 

product. 

Site means any combination of one or more graded pad 

sites, gravel pad sites, foundations, platforms, or the 

immediate physical location upon which equipment is 

physically located. 
93

Smelting furnace means a furnace in which lead-bearing 

materials, carbon-containing reducing agents, and fluxes 

are melted together to form a molten mass of material 

containing lead and slag. 

Solid storage is the storage of manure, typically for 

a period of several months, in unconfined piles or stacks. 

Manure is able to be stacked due to the presence of a 

sufficient amount of bedding material or loss of moisture 

by evaporation. 

Sour gas means any gas that contains significant 

concentrations of hydrogen sulfide. Sour gas may include 

untreated fuel gas, amine stripper off-gas, or sour water 

stripper gas. 

Special naphthas means all finished products with the 

naphtha boiling range (290° to 470 °F) that are generally 

used as paint thinners, cleaners or solvents. These 

products are refined to a specified flash point. Special 

naphthas include all commercial hexane and cleaning 

solvents conforming to ASTM Specification D1836-07, 

Standard Specification for Commercial Hexanes, and D235-02 

(Reapproved 2007), Standard Specification for Mineral 

Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning 

Solvent), respectively. Naphthas to be blended or marketed 

as motor gasoline or aviation gasoline, or that are to be 
94

used as petrochemical and synthetic natural gas (SNG) 

feedstocks are excluded. 

Spent liquor solids means the dry weight of the solids 

in the spent pulping liquor that enters the chemical 

recovery furnace or chemical recovery combustion unit. 

Spent pulping liquor means the residual liquid 

collected from on-site pulping operations at chemical pulp 

facilities that is subsequently fired in chemical recovery 

furnaces at kraft and soda pulp facilities or chemical 

recovery combustion units at sulfite or semi-chemical pulp 

facilities. 

Standard conditions or standard temperature and 

pressure (STP) means 68 degrees Fahrenheit and 14.7 pounds 

per square inch absolute. 

Steam reforming means a catalytic process that 

involves a reaction between natural gas or other light 

hydrocarbons and steam. The result is a mixture of 

hydrogen, carbon monoxide, carbon dioxide, and water. 

Still gas means any form or mixture of gases produced 

in refineries by distillation, cracking, reforming, and 

other processes. The principal constituents are methane, 

ethane, ethylene, normal butane, butylene, propane, and 

propylene. 
95

Storage tank means a vessel (excluding sumps) that is 

designed to contain an accumulation of crude oil, 

condensate, intermediate hydrocarbon liquids, or produced 

water and that is constructed entirely of non-earthen 

materials (e.g., wood, concrete, steel, plastic) that 

provide structural support. 

Sulfur recovery plant means all process units which 

recover sulfur or produce sulfuric acid from hydrogen 

sulfide (H2S) and/or sulfur dioxide (SO2) from a common 

source of sour gas at a petroleum refinery. The sulfur 

recovery plant also includes sulfur pits used to store the 

recovered sulfur product, but it does not include secondary 

sulfur storage vessels or loading facilities downstream of 

the sulfur pits. For example, a Claus sulfur recovery 

plant includes: reactor furnace and waste heat boiler, 

catalytic reactors, sulfur pits, and, if present, oxidation 

or reduction control systems, or incinerator, thermal 

oxidizer, or similar combustion device. Multiple sulfur 

recovery units are a single sulfur recovery plant only when 

the units share the same source of sour gas. Sulfur 

recovery units that receive source gas from completely 

segregated sour gas treatment systems are separate sulfur 

recovery plants. 
96

Supplemental fuel means a fuel burned within a 

petrochemical process that is not produced within the 

process itself. 

Supplier means a producer, importer, or exporter of a 

fossil fuel or an industrial greenhouse gas. 

Taconite iron ore processing means an industrial 

process that separates and concentrates iron ore from 

taconite, a low grade iron ore, and heats the taconite in 

an indurating furnace to produce taconite pellets that are 

used as the primary feed material for the production of 

iron in blast furnaces at integrated iron and steel plants. 

TAME means tertiary amyl methyl ether, 

(CH3)2(C2H5)COCH3). 

Trace concentrations means concentrations of less than 

0.1 percent by mass of the process stream. 

Transform means to use and entirely consume (except 

for trace concentrations) nitrous oxide or fluorinated GHGs 

in the manufacturing of other chemicals for commercial 

purposes. Transformation does not include burning of 

nitrous oxide. 

Transshipment means the continuous shipment of nitrous 

oxide or a fluorinated GHG from a foreign state of origin 

through the United States or its territories to a second 

foreign state of final destination, as long as the shipment 
97

does not enter into United States jurisdiction. A 

transshipment, as it moves through the United States or its 

territories, cannot be re-packaged, sorted or otherwise 

changed in condition. 

Trona means the raw material (mineral) used to 

manufacture soda ash; hydrated sodium bicarbonate carbonate 

(e.g.Na2CO3.NaHCO3.2H2O). 

Ultimate analysis means the determination of the 

percentages of carbon, hydrogen, nitrogen, sulfur, and 

chlorine and (by difference) oxygen in the gaseous products 

and ash after the complete combustion of a sample of an 

organic material. 

Unfinished oils are all oils requiring further 

processing, except those requiring only mechanical 

blending. 

United States means the 50 states, the District of 

Columbia, and U.S. possessions and territories. 

Unstabilized crude oil means, for the purposes of this 

part, crude oil that is pumped from the well to a pipeline 

or pressurized storage vessel for transport to the refinery 

without intermediate storage in a storage tank at 

atmospheric pressures. Unstabilized crude oil is 

characterized by having a true vapor pressure of 5 pounds 

per square inch absolute (psia) or greater. 
98

Valve means any device for halting or regulating the 

flow of a liquid or gas through a passage, pipeline, inlet, 

outlet, or orifice; including, but not limited to, gate, 

globe, plug, ball, butterfly and needle valves. 

Vegetable Oil means oils extracted from vegetation 

that are generally used as a feedstock in making biodiesel. 

Volatile solids are the organic material in livestock 

manure and consist of both biodegradable and nonbiodegradable fractions. 

Waelz kiln means an inclined rotary kiln in which 

zinc–containing materials are charged together with a 

carbon reducing agent (e.g., petroleum coke, metallurgical 

coke, or anthracite coal). 

Waxes means a solid or semi-solid material at 77 °F 

consisting of a mixture of hydrocarbons obtained or derived 

from petroleum fractions, or through a Fischer-Tropsch type 

process, in which the straight chained paraffin series 

predominates. This includes all marketable wax, whether 

crude or refined, with a congealing point between 80 (or 

85) and 240 °F and a maximum oil content of 50 weight 

percent. 

Wool fiberglass means fibrous glass of random texture, 

including fiberglass insulation, and other products listed 

in NAICS 327993. 
99

You means an owner or operator subject to Part 98. 

Zinc smelters means a facility engaged in the 

production of zinc metal, zinc oxide, or zinc alloy 

products from zinc sulfide ore concentrates, zinc calcine, 

or zinc-bearing scrap and recycled materials through the 

use of pyrometallurgical techniques involving the reduction 

and volatization of zinc-bearing feed materials charged to 

a furnace. 

§98.7 What standardized methods are incorporated by 

reference into this part?

The materials listed in this section are incorporated 

by reference in the corresponding sections noted. These 

incorporations by reference were approved by the Director 

of Federal Register in accordance with 5 U.S.C. 552(a) and 

1 CFR part 51. These materials are incorporated as they 

exist on the date of approval, and a notice of any change 

in the materials will be published in the Federal Register. 

The materials are available for purchase at the 

corresponding address in this section. The materials are 

available for inspection at the EPA Docket Center, Public 

Reading Room, EPA West Building, Room 3334, 1301 

Constitution Avenue, NW, Washington, DC, phone (202) 566-

1744 and at the National Archives and Records 

Administration (NARA). For information on the availability 
100

of this material at NARA, call 202-741-6030, or go to: 

http://www.archives.gov/federal_register/code_of_federal_re

gulations/ibr_ locations.html. 

(a) The following material is available for purchase 

from the Association of Fertilizer and Phosphate Chemists 

(AFPC), P. O. Box 1645, Bartow, Florida 33831, 

http://afpc.net. 

(1) Association of Fertilizer and Phosphate Chemists 

Analytical Methods Manual 10th Edition, incorporation by 

reference (IBR) approved for §98.264(a) and §98.264(b). 

(2) [Reserved] 

(b) The following material is available for purchase 

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

Street, N.W., 4th Floor, Washington, DC 20001, (202) 824-

7000, http://www.aga.org. 

(1) AGA Report No. 3 Orifice Metering of Natural Gas 

and Other Related Hydrocarbon Fluids Part 1: General 

Equations & Uncertainty Guidelines (1990), incorporation by 

reference (IBR) approved for §98.34(b) and §98.244(b). 

(2) AGA Report No. 3 Orifice Metering of Natural Gas 

and Other Related Hydrocarbon Fluids Part 2: Specification 

and Installation Requirements (2000), IBR approved for 

§98.34(b) and §98.244(b). 

Deleted: Phosphate Mining 

States Methods Used and 

Adopted by the Association 

of Fertilizer and Phosphate 

Chemists AFPC Manual 10th 

Edition 2009 - Version 1.9, 
101

(3) AGA Report No. 11 Measurement of Natural Gas by 

Coriolis Meter (2003), IBR approved for §98.244(b) and 

§98.254(c). 

(4) AGA Transmission Measurement Committee Report No. 

7 Measurement of Natural Gas by Turbine Meter 

(2006)/February, IBR approved for §98.34(b) and §98.244(b). 

(c) The following material is available for purchase 

from the ASM International, 9639 Kinsman Road, Materials 

Park, OH 44073, (440) 338-5151, 

http://www.asminternational.org. 

(1) ASM CS-104 UNS No. G10460 - Alloy Digest April 

1985 (Carbon Steel of Medium Carbon Content), incorporation 

by reference (IBR) approved for §98.174(b). 

(2) [Reserved] 

(d) The following material is available for purchase 

from the American Society of Mechanical Engineers (ASME), 

Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, 

http://www.asme.org. 

(1) ASME MFC-3M–2004 Measurement of Fluid Flow in 

Pipes Using Orifice, Nozzle, and Venturi, incorporation by 

reference (IBR) approved for §98.34(b), §98.244(b), 

§98.254(c), §98.344(c), and §98.364(e). 
102

(2) ASME MFC-4M–1986 (Reaffirmed 1997) Measurement of 

Gas Flow by Turbine Meters, IBR approved for §98.34(b), 

§98.244(b), §98.254(c), §98.344(c), and §98.364(e). 

(3) ASME MFC-5M–1985 (Reaffirmed 1994) Measurement of 

Liquid Flow in Closed Conduits Using Transit-Time 

Ultrasonic Flowmeters, IBR approved for §98.34(b) and 

§98.244(b). 

(4) ASME MFC-6M–1998 Measurement of Fluid Flow in 

Pipes Using Vortex Flowmeters, IBR approved for §98.34(b), 

§98.244(b), §98.254(c), §98.344(c), and §98.364(e). 

(5) ASME MFC-7M–1987 (Reaffirmed 1992) Measurement of 

Gas Flow by Means of Critical Flow Venturi Nozzles, IBR 

approved for §98.34(b), §98.244(b), §98.254(c), §98.344(c), 

and §98.364(e). 

(6) ASME MFC-9M–1988 (Reaffirmed 2001) Measurement of 

Liquid Flow in Closed Conduits by Weighing Method, IBR 

approved for §98.34(b) and §98.244(b). 

(7) ASME MFC-11M-2006 Measurement of Fluid Flow by 

Means of Coriolis Mass Flowmeters, IBR approved for 

§98.244(b), §98.254(c), and §98.344(c). 

(8) ASME MFC-14M-2003 Measurement of Fluid Flow Using 

Small Bore Precision Orifice Meters, IBR approved for 

§98.244(b), §98.254(c), §98.344(c), and §98.364(e). 
103

(9) ASME MFC-16-2007 Measurement of Liquid Flow in 

Closed Conduits with Electromagnetic Flowmeters, IBR 

approved for §98.244(b). 

(10) ASME MFC-18M-2001 Measurement of Fluid Flow 

Using Variable Area Meters, IBR approved for §98.244(b), 

§98.254(c),§98.344(c), and §98.364(e). 

(11) ASME MFC-22-2007 Measurement of Liquid by 

Turbine Flowmeters, IBR approved for §98.244(b). 

(e) The following material is available for purchase 

from the American Society for Testing and Material (ASTM), 

100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428-B2959, (800) 262-1373, 

http://www.astm.org. 

(1) ASTM C25-06 Standard Test Method for Chemical 

Analysis of Limestone, Quicklime, and Hydrated Lime, 

incorporation by reference (IBR) approved for §98.114(b), 

§98.174(b), §98.184(b), §98.194(c), and §98.334(b). 

(2) ASTM C114-09 Standard Test Methods for Chemical 

Analysis of Hydraulic Cement, IBR approved for §98.84(a), 

§98.84(b), and §98.84(c). 

(3) ASTM D235-02 (Reapproved 2007) Standard 

Specification for Mineral Spirits (Petroleum Spirits) 

(Hydrocarbon Dry Cleaning Solvent), IBR approved for §98.6. 
104

(4) ASTM D240-02 (Reapproved 2007) Standard Test 

Method for Heat of Combustion of Liquid Hydrocarbon Fuels 

by Bomb Calorimeter, IBR approved for §98.34(a) and 

§98.254(e). 

(5) ASTM D388-05 Standard Classification of Coals by 

Rank, IBR approved for §98.6. 

(6) ASTM D910-07a Standard Specification for Aviation 

Gasolines, IBR approved for §98.6. 

(7) ASTM D1298-99 (Reapproved 2005) Standard Test 

Method for Density, Relative Density (Specific Gravity), or 

API Gravity of Crude Petroleum and Liquid Petroleum 

Products by Hydrometer Method, IBR approved for §98.33(a). 

(8) ASTM D1826-94 (Reapproved 2003) Standard Test 

Method for Calorific (Heating) Value of Gases in Natural 

Gas Range by Continuous Recording Calorimeter, IBR approved 

for §98.34(a) and §98.254(e). 

(9) ASTM D1836-07 Standard Specification for 

Commercial Hexanes, IBR approved for §98.6. 

(10) ASTM D1945-03 Standard Test Method for Analysis 

of Natural Gas by Gas Chromatography, IBR approved for 

§98.34(b), §98.74(c), §98.164(b), §98.244(b), §98.254(d), 

and §98.344(b). 

(11) ASTM D1946-90 (Reapproved 2006) Standard 

Practice for Analysis of Reformed Gas by Gas 
105

Chromatography, IBR approved for §98.34(b), §98.74(c), 

§98.164(b), §98.254(d), §98.344(b), and §98.364(c). 

(12) ASTM D2013-07 Standard Practice for Preparing 

Coal Samples for Analysis, IBR approved for §98.164(b). 

(13) ASTM D2234/D2234M-07 Standard Practice for 

Collection of a Gross Sample of Coal, IBR approved for 

§98.164(b). 

(14) ASTM D2502-04 Standard Test Method for 

Estimation of Mean Relative Molecular Mass of Petroleum 

Oils From Viscosity Measurements, IBR approved for 

§98.34(b) and §98.74(c). 

(15) ASTM D2503-92 (Reapproved 2007) Standard Test 

Method for Relative Molecular Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric Measurement of Vapor 

Pressure, IBR approved for §98.34(b) and §98.74(c). 

(16) ASTM D2505-88 (Reapproved 2004)e1 Standard Test 

Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide 

in High-Purity Ethylene by Gas Chromatography, IBR approved 

for §98.244(b). 

(17) ASTM D2597-94 (Reapproved 2004) Standard Test 

Method for Analysis of Demethanized Hydrocarbon Liquid 

Mixtures Containing Nitrogen and Carbon Dioxide by Gas 

Chromatography, IBR approved for §98.164(b). 
106

(18) ASTM D3176-89 (Reapproved 2002) Standard 

Practice for Ultimate Analysis of Coal and Coke, IBR 

approved for §98.74(c), §98.164(b), §98.244(b), §98.254(i), 

§98.284(c), §98.284(d), §98.314(c), §98.314(d), and 

§98.314(f). 

(19) ASTM D3238-95 (Reapproved 2005) Standard Test 

Method for Calculation of Carbon Distribution and 

Structural Group Analysis of Petroleum Oils by the n-d-M 

Method, IBR approved for §98.34(b), §98.74(c), and 

§98.164(b). 

(20) ASTM D3588-98 (Reapproved 2003) Standard 

Practice for Calculating Heat Value, Compressibility 

Factor, and Relative Density of Gaseous Fuels, IBR approved 

for §98.34(a) and §98.254(e). 

(21) ASTM D3682-01 (Reapproved 2006) Standard Test 

Method for Major and Minor Elements in Combustion Residues 

from Coal Utilization Processes, IBR approved for 

§98.144(b). 

(22) ASTM D4057-06 Standard Practice for Manual 

Sampling of Petroleum and Petroleum Products, IBR approved 

for §98.164(b). 

(23) ASTM D4177-95 (Reapproved 2005) Standard 

Practice for Automatic Sampling of Petroleum and Petroleum 

Products, IBR approved for §98.164(b). 
107

(24) ASTM D4809-06 Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter 

(Precision Method), IBR approved for §98.34(a) and 

§98.254(e). 

(25) ASTM D4891-89 (Reapproved 2006), Standard Test 

Method for Heating Value of Gases in Natural Gas Range by 

Stoichiometric Combustion, IBR approved for §98.34(a) and 

§98.254(e). 

(26) ASTM D5291-02 (Reapproved 2007) Standard Test 

Methods for Instrumental Determination of Carbon, Hydrogen, 

and Nitrogen in Petroleum Products and Lubricants, IBR 

approved for §98.34(b), §98.74(c), §98.164(b), §98.244(b), 

§98.254(i). 

(27) ASTM D5373-08 Standard Test Methods for 

Instrumental Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal, IBR approved for 

§98.34(b), §98.74(c), §98.114(b), §98.164(b), §98.174(b), 

§98.184(b), §98.244(b), §98.254(i), §98.274(b), §98.284(c), 

§98.284(d), §98.314(c), §98.314(d), §98.314(f), and 

§98.334(b). 

(28) ASTM D5865-07a Standard Test Method for Gross 

Calorific Value of Coal and Coke, IBR approved for 

§98.34(a). 
108

(29) ASTM D6060-96 (Reapproved 2001) Standard 

Practice for Sampling of Process Vents With a Portable Gas 

Chromatograph, IBR approved for §98.244(b). 

(30) ASTM D6348-03 Standard Test Method for 

Determination of Gaseous Compounds by Extractive Direct 

Interface Fourier Transform Infrared (FTIR) Spectroscopy, 

IBR approved for §98.54(b) and §98.224(b). 

(31) ASTM D6609-08 Standard Guide for Part-Stream 

Sampling of Coal, IBR approved for §98.164(b). 

(32) ASTM D6751-08 Standard Specification for 

Biodiesel Fuel Blend Stock (B100) for Middle Distillate 

Fuels, IBR approved for §98.6. 

(33) ASTM D6866-08 Standard Test Methods for 

Determining the Biobased Content of Solid, Liquid, and 

Gaseous Samples Using Radiocarbon Analysis, IBR approved 

for §98.33(e), §98.34(d), §98.34(e), and §98.36(e). 

(34) ASTM D6883-04 Standard Practice for Manual 

Sampling of Stationary Coal from Railroad Cars, Barges, 

Trucks, or Stockpiles, IBR approved for §98.164(b). 

(35) ASTM D7430-08ae1 Standard Practice for 

Mechanical Sampling of Coal, IBR approved for §98.164(b). 

(36) ASTM D7459-08 Standard Practice for Collection 

of Integrated Samples for the Speciation of Biomass 

(Biogenic) and Fossil-Derived Carbon Dioxide Emitted from 
109

Stationary Emissions Sources, IBR approved for §98.33(e), 

§98.34(d), §98.34(e), and §98.36(e). 

(37) ASTM E359-00 (Reapproved 2005)e1 Standard Test 

Methods for Analysis of Soda Ash (Sodium Carbonate), IBR 

approved for §98.294(a) and §98.294(b). 

(38) ASTM E1019-08 Standard Test Methods for 

Determination of Carbon, Sulfur, Nitrogen, and Oxygen in 

Steel, Iron, Nickel, and Cobalt Alloys by Various 

Combustion and Fusion Techniques, IBR approved for 

§98.174(b). 

(39) ASTM E1747-95 (Reapproved 2005) Standard Guide 

for Purity of Carbon Dioxide Used in Supercritical Fluid 

Applications, IBR approved for 98.424(b). 

(40) ASTM E1915-07a Standard Test Methods for 

Analysis of Metal Bearing Ores and Related Materials by 

Combustion Infrared-Absorption Spectrometry, IBR approved 

for §98.174(b). 

(41) ASTM E1941-04 Standard Test Method for 

Determination of Carbon in Refractory and Reactive Metals 

and Their Alloys, IBR approved for §98.114(b), §98.184(b), 

§98.334(b). 

(42) ASTM UOP539-97 Refinery Gas Analysis by Gas 

Chromatography, IBR approved for §98.164(b), §98.244(b), 

and §98.254(d), and §98.344(b).
110

(43) ASTM D6349-09 Standard Test Method for 

Determination of Major and Minor Elements in Coal, Coke, 

and Solid Residues from Combustion of Coal and Coke by 

Inductively Coupled Plasma—Atomic Emission Spectrometry.

(f) The following material is available for purchase 

from the Gas Processors Association (GPA), 6526 East 60th 

Street, Tulsa, Oklahoma 74143, (918) 493-3872, 

http://www.gasprocessors.com. 

(1) GPA 2172-09 Calculation of Gross Heating Value, 

Relative Density, Compressibility and Theoretical 

Hydrocarbon Liquid Content for Natural Gas Mixtures for 

Custody Transfer, IBR approved for §98.34(a). 

(2) GPA 2261-00 Analysis for Natural Gas and Similar 

Gaseous Mixtures by Gas Chromatography, IBR approved for 

§98.34(a), §98.164(b), §98.254(d), and §98.344(b). 

(g) The following material is available for purchase 

from the International Standards Organization (ISO), 1, ch. 

de la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, 

Switzerland, +41 22 749 01 11, 

http://www.iso.org/iso/home.htm. 

(1) ISO 3170: Petroleum liquids—Manual sampling - 

Third Edition 2004-02-01, IBR approved for §98.164(b). 
111

(2) ISO 3171: Petroleum Liquids—Automatic pipeline 

sampling - Second Edition 1988-12-01, IBR approved for 

§98.164(b). 

(3) ISO 8316: Measurement of Liquid Flow in Closed 

Conduits— Method by Collection of the Liquid in a 

Volumetric Tank (1987-10-01) - First Edition, IBR approved 

for §98.244(b). 

(4) ISO/TR 15349-1: 1998, Unalloyed steel—

Determination of low carbon content. Part 1: Infrared 

absorption method after combustion in an electric 

resistance furnace (by peak separation) (1998-10-15) - 

First Edition, IBR approved for §98.174(b). 

(5) ISO/TR 15349-3: 1998, Unalloyed steel—

Determination of low carbon content. Part 3: Infrared 

absorption method after combustion in an electric 

resistance furnace (with preheating) (1998-10-15) - First 

Edition, IBR approved for §98.174(b). 

(h) The following material is available for purchase 

from the National Lime Association (NLA), 200 North Glebe 

Road, Suite 800, Arlington, Virginia 22203, (703) 243-5463, 

http://www.lime.org. 

(1) CO2 Emissions Calculation Protocol for the Lime 

Industry—English Units Version, February 5, 2008 Revision—
112

National Lime Association, incorporation by reference (IBR) 

approved for §98.194(c) and §98.194(e). 

(2) [Reserved] 

(i) The following material is available for purchase 

from the National Institute of Standards and Technology 

(NIST), 100 Bureau Drive, Stop 1070, Gaithersburg, MD 

20899-1070, (800) 877-8339, http://www.nist.gov/index.html. 

(1) Specifications, Tolerances, and Other Technical 

Requirements For Weighing and Measuring Devices, NIST 

Handbook 44 (2009), incorporation by reference (IBR) 

approved for §98.244(b), §98.254(h), and §98.344(a). 

(2) [Reserved] 

(j) The following material is available for purchase 

from the Technical Association of the Pulp and Paper 

Industry (TAPPI), 15 Technology Parkway South, Norcross, GA 

30092, (800) 332-8686, http://www.tappi.org. 

(1) T650 om-05 Solids Content of Black Liquor, TAPPI, 

incorporation by reference (IBR) approved for §98.276(c) 

and §98.277(d). 

(2) T684 om-06 Gross Heating Value of Black Liquor, 

TAPPI, incorporation by reference (IBR) approved for 

§98.274(b). 

§98.8 What are the compliance and enforcement provisions 

of this part? 
113

Any violation of any requirement of this part shall be 

a violation of the Clean Air Act, including section 114 (42 

U.S.C. §7414). A violation includes but is not limited to 

failure to report GHG emissions, failure to collect data 

needed to calculate GHG emissions, failure to continuously 

monitor and test as required, failure to retain records 

needed to verify the amount of GHG emissions, and failure 

to calculate GHG emissions following the methodologies 

specified in this part. Each day of a violation 

constitutes a separate violation. 

§98.9 Addresses.

All requests, notifications, and communications to the 

Administrator pursuant to this part, other than submittal 

of the annual GHG report, shall be submitted to the 

following address: 

(a) For U.S. mail. Director, Climate Change 

Division, 1200 Pennsylvania Ave., NW., Mail Code: 6207J, 

Washington, DC 20460. 

(b) For package deliveries. Director, Climate Change 

Division, 1310 L St, NW., Washington, DC 20005. 

Table A-1 of Subpart A—Global Warming Potentials (100-Year 

Time Horizon) 

Name CAS # Chemical formula 

Global 

warming 

potential 

(100 yr.)

Carbon dioxide 124-38-9 CO2 1
114

Table A-1 of Subpart A—Global Warming Potentials (100-Year 

Time Horizon) 

Name CAS # Chemical formula 

Global 

warming 

potential 

(100 yr.)

Methane 74-82-8 CH4 21

Nitrous oxide 10024-97-2 N2O 310

HFC-23 75-46-7 CHF3 11,700

HFC-32 75-10-5 CH2F2 650

HFC-41 593-53-3 CH3F 150

HFC-125 354-33-6 C2HF5 2,800

HFC-134 359-35-3 C2H2F4 1,000

HFC-134a 811-97-2 CH2FCF3 1,300

HFC-143 430-66-0 C2H3F3 300

HFC-143a 420-46-2 C2H3F3 3,800

HFC-152 624-72-6 CH2FCH2F 53

HFC-152a 75-37-6 CH3CHF2 140

HFC-161 353-36-6 CH3CH2F 12

HFC-227ea 431-89-0 C3HF7 2,900

HFC-236cb 677-56-5 CH2FCF2CF3 1,340

HFC-236ea 431-63-0 CHF2CHFCF3 1,370

HFC-236fa 690-39-1 C3H2F6 6,300

HFC-245ca 679-86-7 C3H3F5 560

HFC-245fa 460-73-1 CHF2CH2CF3 1,030

HFC-365mfc 406-58-6 CH3CF2CH2CF3 794

HFC-43-10mee 138495-42-8 CF3CFHCFHCF2CF3 1,300

Sulfur hexafluoride 2551-62-4 SF6 23,900

Trifluoromethyl sulphur 

pentafluoride 373-80-8 

SF5CF3 17,700

Nitrogen trifluoride 7783-54-2 NF3 17,200

PFC-14 

(Perfluoromethane) 75-73-0 

CF4 6,500

PFC-116 

(Perfluoroethane) 76-16-4 

C2F6 9,200

PFC-218 

(Perfluoropropane) 76-19-7 

C3F8 7,000

Perfluorocyclopropane 931-91-9 c-C3F6 17,340

PFC-3-1-10 

(Perfluorobutane) 355-25-9 

C4F10 7,000

Perfluorocyclobutane 115-25-3 c-C4F8 8,700

PFC-4-1-12 

(Perfluoropentane) 678-26-2 

C5F12 7,500

PFC-5-1-14 

(Perfluorohexane) 355-42-0 

C6F14 7,400

PFC-9-1-18 306-94-5 C10F18 7,500

HCFE-235da2 (Isoflurane) 26675-46-7 CHF2OCHClCF3 350

HFE-43-10pccc (H-Galden 

1040x) E1730133 CHF2OCF2OC2F4OCHF2 1,870
115

Table A-1 of Subpart A—Global Warming Potentials (100-Year 

Time Horizon) 

Name CAS # Chemical formula 

Global 

warming 

potential 

(100 yr.)

HFE-125 3822-68-2 CHF2OCF3 14,900

HFE-134 1691-17-4 CHF2OCHF2 6,320

HFE-143a 421-14-7 CH3OCF3 756

HFE-227ea 2356-62-9 CF3CHFOCF3 1,540

HFE-236ca12 (HG-10) 78522-47-1 CHF2OCF2OCHF2 2,800

HFE-236ea2 (Desflurane) 57041-67-5 CHF2OCHFCF3 989

HFE-236fa 20193-67-3 CF3CH2OCF3 487

HFE-245cb2 22410-44-2 CH3OCF2CF3 708

HFE-245fa1 84011-15-4 CHF2CH2OCF3 286

HFE-245fa2 1885-48-9 CHF2OCH2CF3 659

HFE-254cb2 425-88-7 CH3OCF2CHF2 359

HFE-263fb2 460-43-5 CF3CH2OCH3 11

HFE-329mcc2 67490-36-2 CF3CF2OCF2CHF2 919

HFE-338mcf2 156053-88-2 CF3CF2OCH2CF3 552

HFE-338pcc13 (HG-01) 188690-78-0 CHF2OCF2CF2OCHF2 1,500

HFE-347mcc3 28523-86-6 CH3OCF2CF2CF3 575

HFE-347mcf2 E1730135 CF3CF2OCH2CHF2 374

HFE-347pcf2 406-78-0 CHF2CF2OCH2CF3 580

HFE-356mec3 382-34-3 CH3OCF2CHFCF3 101

HFE-356pcc3 160620-20-2 CH3OCF2CF2CHF2 110

HFE-356pcf2 E1730137 CHF2CH2OCF2CHF2 265

HFE-356pcf3 35042-99-0 CHF2OCH2CF2CHF2 502

HFE-365mcf3 378-16-5 CF3CF2CH2OCH3 11

HFE-374pc2 512-51-6 CH3CH2OCF2CHF2 557

HFE-449sl (HFE-7100) 

Chemical blend 

163702-07-6 

163702-08-7 

C4F9OCH3

(CF3)2CFCF2OCH3

297

HFE-569sf2 (HFE-7200) 

Chemical blend 

163702-05-4 

163702-06-5 

C4F9OC2H5

(CF3)2CFCF2OC2H5

59

Sevoflurane 28523-86-6 CH2FOCH(CF3)2 345

HFE-356mm1 13171-18-1 (CF3)2CHOCH3 27

HFE-338mmz1 26103-08-2 CHF2OCH(CF3)2 380

(Octafluorotetramethylene)hydroxymethyl group NA X-(CF2)4CH(OH)-X 73

HFE-347mmy1 22052-84-2 CH3OCF(CF3)2 343

Bis(trifluoromethyl)-

methanol 920-66-1 (CF3)2CHOH 195

2,2,3,3,3-

pentafluoropropanol 422-05-9 CF3CF2CH2OH 42

PFPMIE NA 

CF3OCF(CF3)CF2OCF2OC

F3 10,300

NA = not available 

Table A-2 of Subpart A—Units of Measure Conversions. 
116

To convert from To Multiply by 

Kilograms (kg) Pounds (lbs) 2.20462 

Pounds (lbs) Kilograms (kg) 0.45359 

Pounds (lbs) Metric tons 4.53592 x 10-4

Short tons Pounds (lbs) 2,000 

Short tons Metric tons 0.90718 

Metric tons Short tons 1.10231 

Metric tons Kilograms (kg) 1,000 

Cubic meters (m3) Cubic feet (ft3) 35.31467 

Cubic feet (ft3) Cubic meters (m3) 0.028317 

Gallons (liquid, US) Liters (l) 3.78541 

Liters (l) Gallons (liquid, US) 0.26417 

Barrels of Liquid 

Fuel (bbl) 

Cubic meters (m3) 0.15891 

Cubic meters (m3) Barrels of Liquid 

Fuel (bbl) 

6.289 

Barrels of Liquid 

Fuel (bbl) 

Gallons (liquid, US) 42 

Gallons (liquid, US) Barrels of Liquid 

Fuel (bbl) 

0.023810 

Gallons (liquid, US) Cubic meters (m3) 0.0037854 

Liters (l) Cubic meters (m3) 0.001 

Feet (ft) Meters (m) 0.3048 

Meters (m) Feet (ft) 3.28084 

Miles (mi) Kilometers (km) 1.60934 

Kilometers (km) Miles (mi) 0.62137 

Square feet (ft2) Acres 2.29568 x 10-5

Square meters (m2) Acres 2.47105 x 10-4 

Square miles (mi2) Square kilometers 

(km2) 

2.58999 

Degrees Celsius (oC) Degrees Fahrenheit 

(oF) 

oC = (5/9) x ( oF32) 

Degrees Fahrenheit 

(oF) 

Degrees Celsius (oC) oF = (9/5) x oC + 32 

Degrees Celsius (oC) Kelvin (K) K = oC + 273.15 

Kelvin (K) Degrees Rankine (oR) 1.8 

Joules Btu 9.47817 x 10-4

Btu MMBtu 1 x 10-6 

Pascals (Pa) Inches of Mercury 

(in Hg) 

2.95334 x 10-4

Inches of Mercury 

(inHg) 

Pounds per square 

inch (psi) 

0.49110 

Pounds per square 

inch (psi) 

Inches of Mercury 

(in Hg) 

2.03625 

Subpart E—Adipic Acid Production 

§98.50 Definition of Source Category.
117

The adipic acid production source category consists of 

all adipic acid production facilities that use oxidation to 

produce adipic acid. 

§98.51 Reporting threshold. 

You must report GHG emissions under this subpart if 

your facility contains an adipic acid production process 

and the facility meets the requirements of either 

§98.2(a)(1) or (2). 

§98.52 GHGs to report.

(a) You must report N2O process emissions at the 

facility level. 

(b) You must report under subpart C of this part 

(General Stationary Fuel Combustion Sources) the emissions 

of CO2, CH4, and N2O from each stationary combustion unit 

following the requirements of subpart C. 

§98.53 Calculating GHG emissions. 

(a) You must determine annual N2O emissions from 

adipic acid production according to paragraphs (a)(1) or 

(a)(2) of this section. 

(1) Use a site-specific emission factor and 

production data according to paragraphs (b) through (h) of 

this section. 
118

(2) Request Administrator approval for an alternative 

method of determining N2O emissions according to paragraphs 

(a)(2)(i) and (a)(2)(ii) of this section. 

(i) You must submit the request within 45 days 

following promulgation of this subpart or within the first 

30 days of each subsequent reporting year. 

(ii) If the Administrator does not approve your 

requested alternative method within 150 days of the end of 

the reporting year, you must determine the N2O emissions for 

the current reporting period using the procedures specified 

in paragraphs (b) through (h) of this section. 

(b) You must conduct an annual performance test 

according to paragraphs (b)(1) through (b)(3) of this 

section.

(1) You must conduct the test on the waste gas stream 

from the nitric acid oxidation step of the process, 

referred to as the test point, according to the methods 

specified in §98.54(b) through (f). 

(2) You must conduct the performance test under 

normal process operating conditions. 

(3) You must measure the adipic acid production rate 

during the test and calculate the production rate for the 

test period in metric tons per hour. 

Deleted: factor 

Deleted: using

Deleted: d

Deleted: and without using 

N2O abatement technology
119

(c) Using the results of the performance test in 

paragraph (b) of this section, you must calculate an

emission factor for each adipic acid unit according to 

Equation E-1 of this section: 

n

P

C Q

EF

n

N O

N O N

∑

∗ × ∗

=

−

1

7

2

2 ,

1.14 10

(Eq. E-1) 

Where: 

EFN2O,N = Average facility-specific N2O emission factor 

for each adipic acid production unit (lb N2O 

generated/ton adipic acid produced). 

CN2O = N2O concentration per test run during the 

performance test (ppm N2O). 

1.14x10-7 = Conversion factor (lb/dscf-ppm N2O). 

Q = Volumetric flow rate of effluent gas per test 

run during the performance test (dscf/hr). 

P = Production rate per test run during the 

performance test (tons adipic acid 

produced/hr). 

n = Number of test runs. 

(d) If any N2O abatement technology “N” is located 

after your test point, you must determine the destruction 

efficiency according to paragraphs (d)(1), (d)(2), or 

(d)(3) of this section. 

(1) Use the manufacturer’s specified destruction 

efficiency. 

(2) Estimate the destruction efficiency through 

process knowledge. Examples of information that could 

constitute process knowledge include calculations based on 

Deleted: You must determine 

an N2O emissions factor to 

use in Equation E-2 of this 

section according to 

paragraphs (c)(1) or (c)(2) 

of this section. ¶

(1) You may request 

Administrator approval for 

an alternative method of 

determining N2O 

concentration according to 

the procedures in paragraphs 

(a)(2)(i) and (a)(2)(ii) of 

this section. Alternative 

methods include the use of 

N2O CEMs.¶

(2) 

Deleted: facility-specific 

Deleted: s

Comment [A1]: This equation 

was amended to revise the 

term EFN2O,N

Deleted: s

Deleted: text 

Deleted: applicable,

Deleted: for each N2O 

abatement technology used at 

your facility 
120

material balances, process stoichiometry, or previous test 

results provided the results are still relevant to the 

current vent stream conditions. You must document how 

process knowledge was used to determine the destruction 

efficiency. 

(3) Calculate the destruction efficiency by 

conducting an additional performance test on the emissions 

stream following the N2O abatement technology. 

(e) If any N2O abatement technology “N” is located 

after your test point, you must determine the annual amount 

of adipic acid produced while N2O abatement technology “N” 

is operating according to §98.54(f). Then you must 

calculate the abatement factor for N2O abatement technology 

“N” according to Equation E-2 of this section. 

a

a N

N

P

P

AF ,= (Eq. E-2) 

Where: 

AFN = Abatement utilization factor of N2O abatement 

technology “N” (fraction of annual 

production that abatement technology is 

operating). 

Pa,N = Annual adipic acid production during which 

N2O abatement technology “N” was used (ton 

adipic acid produced). 

Pa = Total annual adipic acid production (ton 

acid produced). 

(f) You must determine the annual amount of adipic 

acid produced according to §98.54(f). 

Deleted: applicable

Deleted: g

Deleted: each 

Deleted: used at your 

facility. The abatement 

factor is calculated for 

each adipic acid facility 

Deleted: Abate 

Deleted: and the annual 

adipic acid production 

during which N2O abatement 

is operating
121

(g) You must calculate N2O emissions according to 

paragraph (g)(1) or (g)(2) of this section for each adipic 

acid production unit and sum the unit level emissions to 

determine the emissions for the facility.

(1) If any N2O abatement technology “N” is located 

after your test point, you must use the emissions factor 

(determined in Equation E-1 of this section), the 

destruction efficiency (determined in paragraph (d) of this 

section), the annual adipic acid production (determined in 

paragraph (f) of this section), and the abatement 

utilization factor (determined in paragraph (e) of this 

section), according to Equation E-3a of this section: 

∑

∗ ∗ − ∗

=

N EFN N PaN DFN AFN N O

1

20

2

2205

(1 ( )) (Eq. E-3a) 

Where: 

N2O = Annual N2O mass emissions from adipic acid 

production (metric tons). 

EFN2ON = N2O emissions factor for unit(s) on which N2O 

abatement technology “N” is operating (lb N2O 

generated/ton adipic acid produced). 

PaN = Annual adipic acid produced by unit(s) for 

which N2O abatement technology “N” is operating 

(tons). 

DFN = Destruction efficiency of N2O abatement 

technology “N” (percent of N2O removed from air 

stream). 

AFN = Abatement utilization factor of N2O abatement 

technology “N” (fraction of annual production 

for which N2O abatement technology “N” is 

operating). 

Deleted: annual adipic acid 

production process emissions 

of 

Deleted: by multiplying

Deleted: using 

Deleted: by the total annual 

adipic acid production and 

accounting for N2O abatement

Deleted: Facility-specific 

Deleted: abatement device 

destruction efficiency, 

Deleted: that
122

2205 = Conversion factor (lb/metric ton). 

N = Number of different N2O abatement 

technologies. 

(2) If no N2O abatement technologies are located after 

your test point, you must use the emissions factor 

(determined using Equation E-1 of this section) and the 

annual adipic acid production (determined in paragraph (f) 

of this section) according to Equation E-3b of this section 

for each adipic acid production unit. 

2205

20

2

EFN Pa N O∗

=

(Eq. E-3b)

Where:

N2O = Annual N2O mass emissions from adipic acid 

production (metric tons).

EFN2O = N2O emissions factor (lb N2O generated/ton 

adipic acid produced).

Pa = Annual adipic acid produced (tons).

2205 = Conversion factor (lb/metric ton).

(h) You must determine the amount of process N2O 

emissions that is sold or transferred off site (if 

applicable). You can determine the amount using existing 

process flow meters and N2O analyzers. 

§98.54 Monitoring and QA/QC requirements.

(a) You must conduct a new performance test and 

calculate a new emissions factor for each adipic acid 

production unit according to the frequency specified in 

paragraphs (a)(1) through (a)(3) of this section. 

Deleted: ¶

Deleted: Facility-specific 

Deleted: facility-specific 
123

(1) Conduct the performance test annually. The test 

must be conducted at a point during production that is 

representative of the average emissions from your process. 

You must document the methods used to determine the 

representative point.

(2) Conduct the performance test when your adipic 

acid production process is changed either by altering the 

ratio of cyclohexanone to cyclohexanol or by installing 

abatement equipment. 

(3) If you requested Administrator approval for an 

alternative method of determining N2O emissions under 

§98.53(a)(2), you must conduct the performance test if your 

request has not been approved by the Administrator within 

150 days of the end of the reporting year in which it was 

submitted. 

(b) You must measure the N2O concentration during the 

performance test using one of the methods in paragraphs 

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

(1) EPA Method 320, Measurement of Vapor Phase 

Organic and Inorganic Emissions by Extractive Fourier 

Transform Infrared (FTIR) Spectroscopy in 40 CFR part 63, 

Appendix A; 

(2) ASTM D6348-03 Standard Test Method for 

Determination of Gaseous Compounds by Extractive Direct 

Deleted: concentration 
124

Interface Fourier Transform Infrared (FTIR) Spectroscopy 

(incorporated by reference, see §98.7); or 

(3) An equivalent method, with Administrator 

approval. 

(c) You must determine the adipic acid production 

rate during the performance test according to paragraph 

(c)(1) or (c)(2) of this section. 

(1) Direct measurement (such as using flow meters or 

weigh scales). 

(2) Existing plant procedures used for accounting 

purposes. 

(d) You must determine the volumetric flow rate 

during the performance test in conjunction with the 

applicable EPA methods in 40 CFR part 60, appendices A-1 

through A-4. Conduct three emissions test runs of 1 hour 

each. All QA/QC procedures specified in the reference test 

methods and any associated performance specifications 

apply. For each test, the facility must prepare an 

emissions factor determination report that must include the 

items in paragraphs (d)(1) through (d)(3) of this section: 

(1) Analysis of samples, determination of emissions, 

and raw data. 

(2) All information and data used to derive the 

emissions factor. 

Deleted: (s)

Deleted: conduct all required 

performance tests according 

to the methods in §98.54(b) 
125

(3) The production rate(s) during the performance 

test and how each production rate was determined. 

(e) You must determine the monthly amount of adipic 

acid produced and the monthly amount of adipic acid 

produced during which N2O abatementtechnology, located 

after the test point, is operating according to the methods 

in paragraphs (c)(1) or (c)(2) of this section. 

(f) You must determine the annual amount of adipic 

acid produced and the annual amount of adipic produced

during which N2O abatement technology located after the test 

point is operating by summing the respective monthly adipic 

acid production quantities determined in paragraph (e) of 

this section. 

§98.55 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable, a substitute data value for the missing 

parameter shall be used in the calculations as specified in 

paragraphs (a) and (b) of this section. 

(a) For each missing value of monthly adipic acid 

production, the substitute data shall be the best available 

estimate based on all available process data or data used 

for accounting purposes (such as sales records). 

Deleted: tion quantity

Deleted: tion

Deleted: 

Deleted: tion quantity

Deleted: tion quantity
126

(b) For missing values related to the performance 

test, including emission factors, production rate, and N2O 

concentration, you must conduct a new performance test 

according to the procedures in §98.54 (a) through (d). 

§98.56 Data reporting requirements. 

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

each annual report must contain the information specified 

in paragraphs (a) through (k) of this section at the 

facility level: 

(a) Annual process N2O emissions from adipic acid 

production (metric tons). 

(b) Annual adipic acid production (tons). 

(c) Annual adipic acid production during which N2O 

abatement technology (located after the test point) is 

operating (tons). 

(d) Annual process N2O emissions from adipic acid 

production facility that is sold or transferred off site 

(metric tons). 

(e) Number of abatement technologies (if applicable). 

(f) Types of abatement technologies used (if 

applicable). 

(g) Abatement technology destruction efficiency for 

each abatement technology (percent destruction). 
127

(h) Abatement utilization factor for each abatement 

technology (fraction of annual production that abatement 

technology is operating). 

(i) Number of times in the reporting year that 

missing data procedures were followed to measure adipic 

acid production (months). 

(j) If you conducted a performance test and 

calculated a site-specific emissions factor according to 

§98.53(a)(1), each annual report must also contain the 

information specified in paragraphs (j)(1) through (j)(7) 

of this section for each adipic acid production unit. 

(1) Emission factor (lb N2O/ton adipic acid). 

(2) Test method used for performance test. 

(3) Production rate per test run during performance 

test (tons/hr). 

(4) N2O concentration per test run during performance 

test (ppm N2O). 

(5) Volumetric flow rate per test run during 

performance test (dscf/hr). 

(6) Number of test runs. 

(7) Number of times in the reporting year that a 

performance test had to be repeated (number). 

(k) If you requested Administrator approval for an 

alternative method of determining N2O emissions under 

Deleted: facility

Deleted: s

Deleted: concentration 
128

§98.53(a)(2), each annual report must also contain the 

information specified in paragraphs (k)(1) through (k)(4) 

of this section for each adipic acid production facility. 

(1) Name of alternative method. 

(2) Description of alternative method. 

(3) Request date. 

(4) Approval date. 

§98.57 Records that must be retained. 

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

you must retain the records specified in paragraphs (a) 

through (h) of this section at the facility level: 

(a) Annual adipic acid production capacity (tons). 

(b) Records of significant changes to process. 

(c) Number of facility and unit operating hours in 

calendar year. 

(d) Documentation of how accounting procedures were 

used to estimate production rate. 

(e) Documentation of how process knowledge was used 

to estimate abatement technology destruction efficiency. 

(f) Performance test reports. 

(g) Measurements, records and calculations used to 

determine reported parameters. 

(h) Documentation of the procedures used to ensure 

the accuracy of the measurements of all reported 

Deleted: of N2O emissions
129

parameters, including but not limited to, calibration of 

weighing equipment, flow meters, and other measurement 

devices. The estimated accuracy of measurements made with 

these devices must also be recorded, and the technical 

basis for these estimates must be provided. 

§98.58 Definitions.

All terms used in this subpart have the same meaning 

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

Subpart H—Cement Production 

§98.80 Definition of the source category.

The cement production source category consists of each 

kiln and each in-line kiln/raw mill at any portland cement 

manufacturing facility including alkali bypasses, and 

includes kilns and in-line kiln/raw mills that burn 

hazardous waste. 

§98.81 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a cement production process and the 

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

(2). 

§98.82 GHGs to report.

You must report: 

(a) CO2 process emissions from calcination in each 

kiln. 
130

(b) CO2 combustion emissions from each kiln. 

(c) CH4 and N2O combustion emissions from each kiln. 

You must calculate and report these emissions under subpart 

C of this part (General Stationary Fuel Combustion Sources) 

by following the requirements of subpart C. 

(d) CO2, CH4, and N2O emissions from each stationary 

combustion unit other than kilns. You must report these 

emissions under subpart C of this part (General Stationary 

Fuel Combustion Sources) by following the requirements of 

subpart C. 

§98.83 Calculating GHG emissions. 

You must calculate and report the annual process CO2

emissions from each kiln using the procedure in paragraphs 

(a) and (b) of this section. 

(a) For each cement kiln that meets the conditions 

specified in §98.33(b)(4)(ii) or (b)(4)(iii), you must 

calculate and report under this subpart the combined 

process and combustion CO2 emissions by operating and 

maintaining a CEMS to measure CO2 emissions according to the 

Tier 4 Calculation Methodology specified in §98.33(a)(4) 

and all associated requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel Combustion Sources). 

(b) For each kiln that is not subject to the 

requirements in paragraph (a) of this section, calculate 
131

and report the process and combustion CO2 emissions from the 

kiln by using the procedure in either paragraph (c) or (d) 

of this section. 

(c) Calculate and report under this subpart the 

combined process and combustion CO2 emissions by operating 

and maintaining a CEMS to measure CO2 emissions according to 

the Tier 4 Calculation Methodology specified in 

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

subpart C of this part (General Stationary Fuel Combustion 

Sources). 

(d) Calculate and report process and combustion CO2

emissions separately using the procedures specified in 

paragraphs (d)(1) through (d)(4) of this section. 

(1) Calculate CO2 process emissions from all kilns at 

the facility using Equation H-1 of this section: 

∑

=

= +

k

m

rm

CO Cli mCO

CMF

CO

1

2 2 , 2

(Eq. H-1) 

Where: 

CO2 CMF = Annual process emissions of CO2 from cement 

manufacturing, metric tons. 

CO2 Cli,m = Total annual emissions of CO2 from clinker 

production from kiln m, metric tons. 

CO2 rm = Total annual emissions of CO2 from raw 

materials, metric tons. 

k = Total number of kilns at a cement 

manufacturing facility. 
132

(2) CO2 emissions from clinker production. Calculate 

CO2 emissions from each kiln using Equations H-2 through H-5 

of this section. 

∑ 











∑ 











=

+

=

=

r

i

CKD i

EF iCKD

p

j

Cli j

EF jCli

Cli m

CO

1

2205

2000

) *

,

( , )*(

1

2205

2000

)*

,

( , )*(

2 ,

(Eq. H-2) 

Where: 

Cli,j = Quantity of clinker produced in month j 

from kiln m, tons. 

EFCli,j = Kiln specific clinker emission factor for 

month j for kiln m, metric tons CO2/metric 

ton clinker computed as specified in 

Equation H-3 of this section. 

CKD,i = Cement kiln dust (CKD) not recycled to the 

kiln in quarter i from kiln m, tons. 

EFCKD,i = Kiln specific CKD emission factor for 

quarter i from kiln m, metric tons 

CO2/metric ton CKD computed as specified in 

Equation H-4 of this section. 

p = Number of months for clinker calculation, 

12. 

r = Number of quarters for CKD calculation, 4. 

2000/2205 = Conversion factor to convert tons to metric 

tons. 

(i) Kiln-Specific Clinker Emission Factor. Calculate 

the kiln-specific clinker emission factor using Equation H3 of this section. 

MgO MR ncMgO Cli MgO Cli CaO MR ncCaO Cli CaO EF (CLi )* ( )*

Cli

= − + −

 

(Eq. H-3) 

Where: 

CliCaO = Monthly total CaO content of Clinker, wtfraction. 

ClincCaO = Monthly non-calcined CaO content of Clinker, 

wt-fraction. 

MRCaO = Molecular-weight Ratio of CO2/CaO = 0.785. 
133

CliMgO = Monthly total MgO content of Clinker, wtfraction. 

ClincMgO = Monthly non-calcined MgO content of Clinker, 

wt-fraction. 

MRMgO = Molecular-weight Ratio of CO2/MgO = 1.092. 

Non-calcined CaO is CaO that remains in the clinker in 

the form of CaCO3 and CaO in the clinker that entered the 

kiln as a non-carbonate species. Non-calcined MgO is MgO 

that remains in the clinker in the form of MgCO3 and MgO in 

the clinker that entered the kiln as a non-carbonate 

species. 

(ii) Kiln-Specific CKD Emission Factor. Calculate 

the kiln-specific CKD emission factor for CKD not recycled 

to the kiln using Equation H-4 of this section. 

MgO MR ncMgO CKD MgO CKD CaO MR ncCaO CKD CaO EF (CKD ) * ( ) *

CKD

= − + − (Eq. H-4) 

Where: 

CKDCaO = Quarterly total CaO content of CKD not 

recycled to the kiln, wt-fraction. 

CKDCaO = Quarterly non-calcined CaO content of CKD not 

recycled to the kiln, wt-fraction. 

MRCaO = Molecular-weight Ratio of CO2/CaO = 0.785. 

CKDMgO = Quarterly total MgO content of CKD not 

recycled to the kiln, wt-fraction. 

CKDMgO = Quarterly non-calcined MgO content of CKD not 

recycled to the kiln, wt-fraction. 

MRMgO = Molecular-weight Ratio of CO2/MgO = 1.092. 

Non-calcined CaO is CaO that remains in the CKD in the 

form of CaCO3 and CaO in the CKD that entered the kiln as a 

non-carbonate species. Non-calcined MgO is MgO that remains 
134

in the CKD in the form of MgCO3 and MgO in the CKD that 

entered the kiln as a non-carbonate species. 

(3) CO2 emissions from raw materials. Calculate CO2

emissions from raw materials using Equation H-5 of this 

section: 

2205

2000

12

44

,

1

2 = ∑ ∗ ∗ ∗

=

CO rm TOCrm

m

i

rm (Eq. H-5) 

Where: 

rm = The amount of raw material i consumed 

annually, tons/yr (dry basis) or the amount of 

raw kiln feed consumed annually, tons/yr (dry 

basis). 

CO2,rm = Annual CO2 emissions from raw materials. 

TOCrm = Organic carbon content of raw material i or 

organic carbon content of combined raw kiln 

feed(dry basis), as determined in §98.84(c) or 

using a default factor of 0.2 percent of total 

raw material weight. 

M = Number of raw materials or 1 if calculating 

emissions based on combined raw kiln feed. 

44/12 = Ratio of molecular weights, CO2 to carbon . 

2000/2205 = Conversion factor to convert tons to metric 

tons. 

(4) Calculate and report under subpart C of this part 

(General Stationary Fuel Combustion Sources) the combustion 

CO2 emissions from the kiln according to the applicable 

requirements in subpart C. 

§98.84 Monitoring and QA/QC requirements. 

(a) You must determine the weight fraction of total 

CaO and total MgO in CKD not recycled to the kiln from each 

kiln using ASTM C114-09, Standard Test Methods for Chemical 
135

Analysis of Hydraulic Cement (incoporated by reference, see 

§98.7). The monitoring must be conducted quarterly for each 

kiln from a CKD sample drawn either as CKD is exiting the 

kiln or from bulk CKD storage. 

(b) You must determine the weight fraction of total 

CaO and total MgO in clinker from each kiln using ASTM 

C114-09 Standard Test Methods for Chemical Analysis of 

Hydraulic Cement (incorporated by reference, see §98.7). 

The monitoring must be conducted monthly for each kiln from 

a monthly clinker sample drawn from bulk clinker storage if 

storage is dedicated to the specific kiln, or from a 

monthly arithmetic average of daily clinker samples drawn 

from the clinker conveying systems exiting each kiln. 

(c) The total organic carbon content (dry basis) of 

raw materials must be determined annually using ASTM C114-

09 Standard Test Methods for Chemical Analysis of Hydraulic 

Cement (incorporated by reference, see §98.7) or a similar 

industry standard practice or method approved for total 

organic carbon determination in raw mineral materials. The 

analysis must be conducted either on sample material drawn 

from bulk raw kiln feed storage or on sample material drawn 

from bulk raw material storage for each category of raw 

material (i.e., limestone, sand, shale, iron oxide, and 

alumina). Facilities that opt to use the default total 

Deleted: 07 

Deleted: s

Deleted: each 
136

organic carbon factor provided in §98.83(d)(3), are not 

required to monitor for TOC. 

(d) The quantity of clinker produced monthly by each 

kiln must be determined by direct weight measurement of 

clinker using the same plant techniques used for accounting 

purposes, such as reconciling weigh hopper or belt weigh 

feeder measurements against inventory measurements. As an 

alternative, facilities may also determine clinker 

production by direct measurement of raw kiln feed and 

application of a kiln-specific feed-to-clinker factor. 

Facilities that opt to use a feed-to-clinker factor must 

verify the accuracy of this factor on a monthly basis. 

(e) The quantity of CKD not recycled to the kiln by 

each kiln must be determined quarterly by direct weight 

measurement using the same plant instruments used for 

accounting purposes, such as weigh hoppers, truck weigh 

scales, or belt weigh feeders. 

(f) The annual quantity of raw kiln feed or annual 

quantity of each category of raw materials consumed by the 

facility (e.g., limestone, sand, shale, iron oxide, and 

alumina) must be determined monthly by direct weight 

measurement using the same plant instruments used for 

accounting purposes, such as weigh hoppers, truck weigh 

scales, or belt weigh feeders. 

Deleted: instruments

Deleted: s

Deleted: s

Deleted: annually 
137

(g) The monthly non-calcined CaO and MgO that remains 

in the clinker in the form of CaCO3 or that enters the kiln 

as a non-carbonate species may be assumed to be a default 

value of 0.0 or may be determined monthly by careful 

chemical analysis of feed material and clinker material 

from each kiln using well documented analytical and 

calculational methods or the appropriate industry standard 

practice. 

(h) The quarterly non-calcined CaO and MgO that 

remains in the CKD in the form of CaCO3 or that enters the 

kiln as a non-carbonate species may be assumed to be a 

default value of 0.0 or may be determined quarterly by 

careful chemical analysis of feed material and CKD material 

from each kiln using well documented analytical and 

calculational methods or the appropriate industry standard 

practice. 

§98.85 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations in §98.83 is required. 

Therefore, whenever a quality-assured value of a required 

parameter is unavailable, a substitute data value for the 

missing parameter shall be used in the calculations. The 

owner or operator must document and keep records of the 

procedures used for all such estimates. 
138

(a) If the CEMS approach is used to determine 

combined process and combustion CO2 emissions, the missing 

data procedures in §98.35 apply. 

(b) For CO2 process emissions from cement 

manufacturing facilities calculated according to §98.83(d), 

if data on the carbonate content (of clinker or CKD), 

noncalcined content (of clinker or CKD) or the annual 

organic carbon content of raw materials are missing, 

facilities must undertake a new analysis. 

(c) For each missing value of monthly clinker 

production the substitute data value must be the best 

available estimate of the monthly clinker production based 

on information used for accounting purposes, or use the 

maximum tons per day capacity of the system and the number 

of days per month. 

(d) For each missing value of monthly raw material 

consumption the substitute data value must be the best 

available estimate of the monthly raw material consumption 

based on information used for accounting purposes (such as 

purchase records), or use the maximum tons per day raw 

material throughput of the kiln and the number of days per 

month. 

§98.86 Data reporting requirements. 
139

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

each annual report must contain the information specified 

in paragraphs (a) and (b) of this section, as appropriate. 

(a) If a CEMS is used to measure CO2 emissions, then 

you must report under this subpart the relevant information 

required by §98.36(e)(2)(vi) and the information listed in 

this paragraph(a): 

(1) Monthly clinker production from each kiln at the 

facility. 

(2) Monthly cement production from each kiln at the 

facility. 

(3) Number of kilns and number of operating kilns. 

(b) If a CEMS is not used to measure CO2 emissions, 

then you must report the information listed in this 

paragraph (b) for each kiln: 

(1) Kiln identification number. 

(2) Monthly clinker production from each kiln. 

(3) Monthly cement production from each kiln. 

(4) Number of kilns kilns and number of operating 

kilns. 

(5) Quarterly quantity of CKD not recycled to the 

kiln for each kiln at the facility. 
140

(6) Monthly fraction of total CaO, total MgO, noncalcined CaO and non-calcined MgO in clinker for each kiln 

(as wt-fractions). 

(7) Method used to determine non-calcined CaO and 

non-calcined MgO in clinker. 

(8) Quarterly fraction of total CaO, total MgO, noncalcined CaO and non-calcined MgO in CKD not recycled to 

the kiln for each kiln (as wt-fractions). 

(9) Method used to determine non-calcined CaO and 

non-calcined MgO in CKD. 

(10) Monthly kiln-specific clinker CO2 emission 

factors for each kiln (metric tons CO2/metric ton clinker 

produced). 

(11) Quarterly kiln-specific CKD CO2 emission factors 

for each kiln (metric tons CO2/metric ton CKD produced). 

(12) Annual organic carbon content of raw kiln feed 

or annual organic carbon content of each raw material (wtfraction, dry basis). 

(13) Annual consumption of raw kiln feed or annual 

consumption of each raw material (dry basis). 

(14) Number of times missing data procedures were 

used to determine the following information: 

(i) Clinker production (number of months). 
141

(ii) Carbonate contents of clinker (number of 

months). 

(iii) Non-calcined content of clinker (number of 

months). 

(iv) CKD not recycled to kiln (number of quarters). 

(v) Non-calcined content of CKD (number of quarters) 

(vi) Organic carbon contents of raw materials 

(number of times). 

(vii) Raw material consumption (number of months). 

(15) Method used to determine the monthly clinker 

production from each kiln reported under (b)(2) of this 

section, including monthly kiln-specific clinker factors, 

if used.

§98.87 Records that must be retained.

(a) If a CEMS is used to measure CO2 emisions, then in 

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

retain under this subpart the records required for the Tier 

4 Calculation Methodology in §98.37. 

(1) [Reserved]

(2) [Reserved]

(3) Measurements, records and calculations used to 

determine reported parameters. 

(b) If a CEMS is not used to measure CO2 emissions, 

then in addition to the records required by §98.3(g), you 

Deleted: Documentation of 

monthly calculated kilnspecific clinker CO2

emission factor.¶

Deleted: Documentation of 

quarterly calculated kilnspecific CKD CO2 emission 

factor.¶
142

must retain the records specified in paragraphs (a) through 

(b) of this section for each portland cement manufacturing 

facility.

(1) Documentation of monthly calculated kiln-specific 

clinker CO2 emission factor.

(2) Documentation of quarterly calculated kilnspecific CKD CO2 emission factor.

(3) Measurements, records and calculations used to 

determine reported parameters.

§98.88 Definitions.

All terms used in this subpart have the same meaning 

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

Subpart K—Ferroalloy Production 

§98.110 Definition of the source category.

The ferroalloy production source category consists of 

any facility that uses pyrometallurgical techniques to 

produce any of the following metals: ferrochromium, 

ferromanganese, ferromolybdenum, ferronickel, ferrosilicon, 

ferrotitanium, ferrotungsten, ferrovanadium, 

silicomanganese, or silicon metal. 

§98.111 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a ferroalloy production process and 
143

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

or (2). 

§98.112 GHGs to report.

You must report: 

(a) Process CO2 emissions from each electric arc 

furnace (EAF) used for the production of any ferroalloy 

listed in §98.110, and process CH4 emissions from each EAF 

that is used for the production of any ferroalloy listed in 

Table K-1 of this section.

(b) CO2, CH4, and N2O emissions from each stationary 

combustion unit following the requirements of subpart C of 

this part. You must report these emissions under subpart C 

of this part (General Stationary Fuel Combustion Sources). 

§98.113 Calculating GHG emissions.

You must calculate and report the annual process CO2

emissions from each EAF not subject to paragraph (c) of 

this section using the procedures in either paragraph (a) 

or (b) of this section. For each EAF also subject to 

annual process CH4 emissions reporting, you must also 

calculate and report the annual process CH4 emissions from 

the EAF using the procedures in paragraph (d) of this 

section. 

(a) Calculate and report under this subpart the 

process CO2 emissions by operating and maintaining CEMS 
144

according to the Tier 4 Calculation Methodology in 

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

subpart C of this part (General Stationary Fuel Combustion 

Sources). 

(b) Calculate and report under this subpart the 

annual process CO2 emissions using the procedure in either 

paragraph (b)(1) or (b)(2) of this section. 

(1) Calculate and report under this subpart the 

annual process CO2 emissions from EAFs by operating and 

maintaining a CEMS according to the Tier 4 Calculation 

Methodology specified in §98.33(a)(4) and the applicable 

requirements for Tier 4 in subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(2) Calculate and report under this subpart the 

annual process CO2 emissions from the EAFs using the carbon 

mass balance procedure specified in paragraphs (b)(2)(i) 

and (b)(2)(ii) of this section. 

(i) For each EAF, determine the annual mass of carbon 

in each carbon-containing input and output material for the 

EAF and estimate annual process CO2 emissions from the EAF 

using Equation K-1 of this section. Carbon-containing 

input materials include carbon electrodes and carbonaceous 

reducing agents. If you document that a specific input or 

output material contributes less than 1 percent of the 
145

total carbon into or out of the process, you do not have to 

include the material in your calculation using Equation K-1 

of this section. 

( )

( )

( )

( )

( )

∑ ( )

∑

∑

∑

∑

∑

× × ×

× × ×

+ × × ×

+ × × ×

+ × × ×

= × × ×

l

l

non product outgoing lnon product outgoing

k

k

product outgoing kproduct outgoing

j

h

ore ore

m

electrode electrode m

i

i

reducing agent ireducing agent

M C

M C

M

M C

M C

M C

h h

m

1

- -

1

1

flux j flux j

1

1

1

CO2

2205

2000

12

44

-

2205

2000

12

44

-

C

2205

2000

12

44

2205

2000

12

44

2205

2000

12

44

2205

2000

12

44 E

(Eq. K-1) 

Where: 

ECO2 = Annual process CO2 emissions from an 

individual EAF (metric tons). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

2000/2205 = Conversion factor to convert tons to 

metric tons. 

Mreducing agenti= Annual mass of reducing agent i fed, 

charged, or otherwise introduced into the 

EAF (tons). 

Creducing agenti= Carbon content in reducing agent i 

(percent by weight, expressed as a 

decimal fraction). 

Melectrodem= Annual mass of carbon electrode m

consumed in the EAF (tons). 

Celectrodem= Carbon content of the carbon electrode m

(percent by weight, expressed as a 

decimal fraction). 

Moreh

 = Annual mass of ore h charged to the EAF 

(tons). 

Coreh = Carbon content in ore h (percent by 

weight, expressed as a decimal fraction). 
146

Mfluxj

 = Annual mass of flux material j fed, 

charged, or otherwise introduced into the 

EAF to facilitate slag formation (tons). 

Cfluxj

 = Carbon content in flux material j

(percent by weight, expressed as a 

decimal fraction). 

Mproductk

 = Annual mass of alloy product k tapped 

from EAF (tons). 

Cproductk = Carbon content in alloy product k. 

(percent by weight, expressed as a 

decimal fraction). 

Mnon-product outgoingl = Annual mass of non-product outgoing 

material l removed from EAF (tons). 

Cnon-product outgoingl = Carbon content in non-product outgoing 

material l (percent by weight, expressed 

as a decimal fraction). 

(ii) Determine the combined annual process CO2

emissions from the EAFs at your facility using Equation K-2 

of this section. 

=∑

k

1

2 CO2 k

CO E (Eq. K-2) 

Where: 

CO2 = Annual process CO2 emissions from EAFs at facility 

used for the production of any ferroalloy listed in 

§98.110 (metric tons). 

ECO2k= Annual process CO2 emissions calculated from EAF k

calculated using Equation K-1 of this section 

(metric tons). 

k = Total number of EAFs at facility used for the 

production of any ferroalloy listed in §98.110. 

(c) If GHG emissions from an EAF are vented through 

the same stack as any combustion unit or process equipment 

that reports CO2 emissions using a CEMS that complies with 

the Tier 4 Calculation Methodology in subpart C of this 

part (General Stationary Fuel Combustion Sources), then the 
147

calculation methodology in paragraph (b) of this section 

shall not be used to calculate process emissions. The 

owner or operator shall report under this subpart the 

combined stack emissions according to the Tier 4 

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

requirements for Tier 4 in subpart C of this part. 

(d) For the EAFs at your facility used for the 

production of any ferroalloy listed in Table K-1 of this 

subpart, you must calculate and report the annual CH4

emissions using the procedure specified in paragraphs 

(d)(1) and (2) of this section. 

(1) For each EAF, determine the annual CH4 emissions 

using Equation K-3 of this section. 

∑ 











=

i

i

product i

ECH Mproduct x x EF

1

4

2005

2000 ( (Eq. K-3) 

Where: 

ECH4 = Annual process CH4 emissions from an 

individual EAF (metric tons). 

Mproducti= Annual mass of alloy product i produced in 

the EAF (tons). 

2000/2205 =Conversion factor to convert tons to metric 

tons. 

EFproducti = CH4 emission factor for alloy product i from 

Table K-1 in this subpart (kg of CH4

emissions per metric ton of alloy product 

i). 
148

(2) Determine the combined process CH4 emissions from 

the EAFs at your facility using Equation K-4 of this 

section: 

= ∑

j

1

4 CH4 j CH E (Eq. K-4) 

Where: 

CH4 = Annual process CH4 emissions from EAFs at facility 

used for the production of ferroalloys listed in 

Table K-1 of this subpart (metric tons). 

ECH4j= Annual process CH4 emissions from EAF j calculated 

using Equation K-3 of this section (metric tons). 

j = Total number of EAFs at facility used for the 

production of ferroalloys listed in Table K-1 of 

this subpart. 

§98.114 Monitoring and QA/QC requirements.

If you determine annual process CO2 emissions using the 

carbon mass balance procedure in §98.113(b)(2), you must 

meet the requirements specified in paragraphs (a) and (b) 

of this section. 

(a) Determine the annual mass for each material used 

for the calculations of annual process CO2 emissions using 

Equation K-1 of this subpart by summing the monthly mass 

for the material determined for each month of the calendar 

year. The monthly mass may be determined using plant 

instruments used for accounting purposes, including either 

direct measurement of the quantity of the material placed 
149

in the unit or by calculations using process operating 

information. 

(b) For each material identified in paragraph (a) of 

this section, you must determine the average carbon content 

of the material consumed, used, or produced in the calendar 

year using the methods specified in either paragraph (b)(1) 

or (b)(2) of this section. If you document that a specific 

process input or output contributes less than one percent 

of the total mass of carbon into or out of the process, you 

do not have to determine the monthly mass or annual carbon 

content of that input or output. 

(1) Information provided by your material supplier. 

(2) Collecting and analyzing at least three 

representative samples of the material inputs and outputs 

each year. The carbon content of the material must be 

analyzed at least annually using the standard methods (and 

their QA/QC procedures) specified in paragraphs (b)(2)(i) 

through (b)(2)(iii) of this section, as applicable. 

(i) ASTM E1941-04, Standard Test Method for 

Determination of Carbon in Refractory and Reactive Metals 

and Their Alloys (incorporated by reference, see §98.7) for 

analysis of metal ore and alloy product. 

(ii) ASTM D5373-08 Standard Test Methods for 

Instrumental Determination of Carbon, Hydrogen, and 
150

Nitrogen in Laboratory Samples of Coal (incorporated by 

reference, see §98.7), for analysis of carbonaceous 

reducing agents and carbon electrodes. 

(iii) ASTM C25-06, Standard Test Methods for Chemical 

Analysis of Limestone, Quicklime, and Hydrated Lime 

(incorporated by reference, see §98.7) for analysis of flux 

materials such as limestone or dolomite. 

§98.115 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations in §98.113 is required. 

Therefore, whenever a quality-assured value of a required 

parameter is unavailable, a substitute data value for the 

missing parameter shall be used in the calculations as 

specified in the paragraphs (a) and (b) of this section. 

You must document and keep records of the procedures used 

for all such estimates. 

(a) If you determine CO2 emissions for the EAFs at 

your facility using the carbon mass balance procedure in 

§98.113(b), 100 percent data availability is required for 

the carbon content of the input and output materials. You 

must repeat the test for average carbon contents of inputs 

according to the procedures in §98.114(b) if data are 

missing. 
151

(b) For missing records of the monthly mass of 

carbon-containing inputs and outputs, the substitute data 

value must be based on the best available estimate of the 

mass of the inputs and outputs from on all available 

process data or data used for accounting purposes, such as 

purchase records. 

(c) If you are required to calculate CH4 emissions for 

an EAF at your facility as specified in §98.113(d), the 

estimate is based an annual quantity of certain alloy 

products, so 100 percent data availability is required. 

§98.116 Data reporting requirements.

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

each annual report must contain the information specified 

in paragraphs (a) through (e) of this section, as 

applicable: 

(a) Annual facility ferroalloy product production 

capacity (tons). 

(b) Annual production for each ferroalloy product 

identified in §98.110, from each EAF (tons). 

(c) Total number of EAFs at facility used for 

production of ferroalloy products. 

(d) If a CEMS is used to measure CO2 emissions, then 

you must report under this subpart the relevant information 

required by §98.36 for the Tier 4 Calculation Methodology 

Deleted: (tons) 

Deleted: as applicable

Deleted: reported in 

paragraph (a)(4) of this 

section

Deleted: 37 
152

and the following information specified in paragraphs 

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

(1) Annual process CO2 emissions (in metric tons) from 

each EAF used for the production of any ferroalloy product 

identified in §98.110 . 

(2) Annual process CH4 emissions (in metric tons) from 

each EAF used for the production of any ferroalloy listed 

in Table K-1 of this subpart (metric tons). 

(3) Identification number of each EAF. 

(e) If a CEMS is not used to measure CO2 process 

emissions, and the carbon mass balance procedure is used to 

determine CO2 emissions according to the requirements in 

§98.113(b), then you must report the following information 

specified in paragraphs (e)(1) through (e)(7) of this 

section. 

(1) Annual process CO2 emissions (in metric tons) from 

each EAF used for the production of any ferroalloy 

identified in §98.110 (metric tons). 

(2) Annual process CH4 emissions (in metric tons) from 

each EAF used for the production of any ferroalloy listed 

in Table K-1 of this subpart (metric tons). 

(3) Identification number of each EAF. 

Deleted: listed in Table K-1 

of this subpart (metric 

tons)

Deleted: listed in Table K-1 

of this subpart
153

(4) Annual material quantity for each material 

included for the calculation of annual process CO2 emissions 

for each EAF. 

(5) Annual average of the carbon content 

determinations for each material included for the 

calculation of annual process CO2 emissions for each EAF 

(percent by weight, expressed as a decimal fraction). 

(6) List the method used for the determination of 

carbon content for each material reported in paragraph 

(e)(5) of this section (e.g., supplier provided 

information, analyses of representative samples you 

collected). 

(7) If you use the missing data procedures in 

§98.115(b), you must report how monthly mass of carboncontaining inputs and outputs with missing data was 

determined and the number of months the missing data 

procedures were used. 

§98.117 Records that must be retained.

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

must retain the records specified in paragraphs (a) through 

(d) of this section for each EAF, as applicable. 

(a) If a CEMS is used to measure CO2 emissions 

according to the requirements in §98.113(a), then you must 

retain under this subpart the records required for the Tier 
154

4 Calculation Methodology in §98.37 and the information 

specified in paragraphs (a)(1) through (a)(3) of this 

section. 

(1) Monthly EAF production quantity for each 

ferroalloy product (tons). 

(2) Number of EAF operating hours each month. 

(3) Number of EAF operating hours in a calendar year. 

(b) If the carbon mass balance procedure is used to 

determine CO2 emissions according to the requirements in 

§98.113(b)(2), then you must retain records for the 

information specified in paragraphs (b)(1) through (b)(5) 

of this section. 

(1) Monthly EAF production quantity for each 

ferroalloy product (tons). 

(2) Number of EAF operating hours each month. 

(3) Number of EAF operating hours in a calendar year. 

(4) Monthly material quantity consumed, used, or 

produced for each material included for the calculations of 

annual process CO2 emissions (tons). 

(5) Average carbon content determined and records of 

the supplier provided information or analyses used for the 

determination for each material included for the 

calculations of annual process CO2 emissions. 
155

(c) You must keep records that include a detailed 

explanation of how company records of measurements are used 

to estimate the carbon input and output to each EAF, 

including documentation of specific input or output 

materials excluded from Equation K-1 of this subpart that 

contribute less than 1 percent of the total carbon into or 

out of the process. You also must document the procedures 

used to ensure the accuracy of the measurements of 

materials fed, charged, or placed in an EAF including, but 

not limited to, calibration of weighing equipment and other 

measurement devices. The estimated accuracy of 

measurements made with these devices must also be recorded, 

and the technical basis for these estimates must be 

provided. 

(d) If you are required to calculate CH4 emissions for 

the EAF as specified in §98.113(d), you must maintain 

records of the total amount of each alloy product produced 

for the specified reporting period, and the appropriate 

alloy-product specific emission factor used to calculate 

the CH4 emissions. 

§98.118 Definitions.

All terms used of this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part. 
156

Table K-1 of Subpart K—Electric Arc Furnace (EAF) CH4

Emission Factors. 

CH4 Emission Factor 

(kg CH4 per metric ton product) 

EAF Operation 

Alloy product 

produced in EAF 

BatchCharging SprinkleCharginga

SprinkleCharging and 

>750°Cb

Silicon metal 1.5 1.2 0.7 

Ferrosilicon 90% 1.4 1.1 0.6 

Ferrosilicon 75% 1.3 1.0 0.5 

Ferrosilicon 65% 1.3 1.0 0.5 

a Sprinkle-charging is charging intermittently every minute. 

b Temperature measured in off-gas channel downstream of the 

furnace hood. 

Subpart N—Glass Production 

§98.140 Definition of the source category.

(a) A glass manufacturing facility manufactures flat 

glass, container glass, pressed and blown glass, or wool 

fiberglass by melting a mixture of raw materials to produce 

molten glass and form the molten glass into sheets, 

containers, fibers, or other shapes. A glass manufacturing 

facility uses one or more continuous glass melting furnaces 

to produce glass. 

(b) A glass melting furnace that is an experimental 

furnace or a research and development process unit is not 

subject to this subpart. 

§98.141 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a glass production process and the 
157

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

(2). 

§98.142 GHGs to report.

You must report: 

(a) CO2 process emissions from each continuous glass 

melting furnace. 

(b) CO2 combustion emissions from each continuous 

glass melting furnace. 

(c) CH4 and N2O combustion emissions from each 

continuous glass melting furnace. You must calculate and 

report these emissions under subpart C of this part 

(General Stationary Fuel Combustion Sources) by following 

the requirements of subpart C. 

(d) CO2, CH4, and N2O emissions from each stationary 

fuel combustion unit other than continuous glass melting 

furnaces. You must report these emissions under subpart C 

of this part (General Stationary Fuel Combustion Sources) 

by following the requirements of subpart C. 

§98.143 Calculating GHG emissions.

You must calculate and report the annual process CO2

emissions from each continuous glass melting furnace using 

the procedure in paragraphs (a) and (b) of this section. 

(a) For each continuous glass melting furnace that 

meets the conditions specified in §98.33(b)(4)(ii) or 
158

(iii), you must calculate and report under this subpart the 

combined process and combustion CO2 emissions by operating 

and maintaining a CEMS to measure CO2 emissions according to 

the Tier 4 Calculation Methodology specified in 

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

subpart C of this part (General Stationary Fuel Combustion 

Sources). 

(b) For each continuous glass melting furnace that is 

not subject to the requirements in paragraph (a) of this 

section, calculate and report the process and combustion CO2

emissions from the glass melting furnace by using either 

the procedure in paragraph (b)(1) of this section or the 

procedure in paragraphs (b)(2) through (b)(7) of this 

section, except as specified in paragraph (c) of this 

section. 

(1) Calculate and report under this subpart the 

combined process and combustion CO2 emissions by operating 

and maintaining a CEMS to measure CO2 emissions according to 

the Tier 4 Calculation Methodology specified in 

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

subpart C of this part (General Stationary Fuel Combustion 

Sources). 
159

(2) Calculate and report the process and combustion 

CO2 emissions separately using the procedures specified in 

paragraphs (b)(2)(i) through (b)(2)(vi) of this section. 

(i) For each carbonate-based raw material charged to 

the furnace, obtain from the supplier of the raw material 

the carbonate-based mineral mass fraction. 

(ii) Determine the quantity of each carbonate-based 

raw material charged to the furnace. 

(iii) Apply the appropriate emission factor for each 

carbonate-based raw material charged to the furnace, as 

shown in Table N-1 to this subpart. 

(iv) Use Equation N-1 of this section to calculate 

process mass emissions of CO2 for each furnace: 

∑=

= • • • •

n

i 1

CO2 i i EFi Fi

)

2205

2000 E MF (M (Eq. N-1) 

Where: 

ECO2 = Process emissions of CO2 from the furnace 

(metric tons). 

n = Number of carbonate-based raw materials 

charged to furnace. 

MFi = Annual average mass fraction of carbonatebased mineral i in carbonate-based raw 

material i (percentage, expressed as a 

decimal). 

Mi = Annual amount of carbonate-based raw material 

i charged to furnace (tons). 

2000/2205 = Conversion factor to convert tons to metric 

tons. 
160

EFi = Emission factor for carbonate-based raw 

material i (metric ton CO2 per metric ton 

carbonate-based raw material as shown in 

Table N-1 to this subpart). 

Fi = Fraction of calcination achieved for 

carbonate-based raw material i, assumed to 

be equal to 1.0 (percentage, expressed as a 

decimal). 

(v) You must calculate the total process CO2 emissions 

from continuous glass melting furnaces at the facility 

using Equation N-2 of this section: 

∑=

=

k

i

CO ECO i

1

2 2

(Eq. N-2) 

Where: 

CO2 = Annual process CO2 emissions from glass 

manufacturing facility (metric tons). 

ECO2i = Annual CO2 emissions from glass melting furnace i 

(metric tons). 

k = Number of continuous glass melting furnaces. 

(vi) Calculate and report under subpart C of this 

part (General Stationary Fuel Combustion Sources) the 

combustion CO2 emissions in the glass furnace according to 

the applicable requirements in subpart C. 

(c) As an alternative to data provided by the raw 

material supplier, a value of 1.0 can be used for the mass 

fraction (MFi) of carbonate-based mineral i in Equation N-1 

of this section. 

§98.144 Monitoring and QA/QC requirements.
161

(a) You must measure annual amounts of carbonatebased raw materials charged to each continuous glass 

melting furnace from monthly measurements using plant 

instruments used for accounting purposes, such as 

calibrated scales or weigh hoppers. Total annual mass 

charged to glass melting furnaces at the facility shall be 

compared to records of raw material purchases for the year. 

(b) You must measure carbonate-based mineral mass 

fractions at least annually to verify the mass fraction 

data provided by the supplier of the raw material; such 

measurements shall be based on sampling and chemical 

analysis conducted by a certified laboratory using ASTM 

D3682-01 (Reapproved 2006) Standard Test Method for Major 

and Minor Elements in Combustion Residues from Coal 

Utilization Processes (incorporated by reference, see 

§98.7) or ASTM D6349-09 Standard Test Method for 

Determination of Major and Minor Elements in Coal, Coke, 

and Solid Residues from Combustion of Coal and Coke by 

Inductively Coupled Plasma—Atomic Emission Spectrometry 

(incorporated by reference, see §98.7). 

(c) You must determine the annual average mass 

fraction for the carbonate-based mineral in each carbonatebased raw material by calculating an arithmetic average of 
162

the monthly data obtained from raw material suppliers or 

sampling and chemical analysis. 

(d) You must determine on an annual basis the 

calcination fraction for each carbonate consumed based on 

sampling and chemical analysis using an industry consensus 

standard. This chemical analysis must be conducted using 

an x-ray fluorescence test or other enhanced testing method 

published by an industry consensus standards organization 

(e.g., ASTM, ASME, API, etc.). 

§98.145 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations is required (e.g., carbonate 

raw materials consumed, etc.). If the monitoring and 

quality assurance procedures in §98.144 cannot be followed 

and data is missing, you must use the most appropriate of 

the missing data procedures in paragraphs (a) and (b) of 

this section. You must document and keep records of the 

procedures used for all such missing value estimates. 

(a) For missing data on the monthly amounts of 

carbonate-based raw materials charged to any continuous 

glass melting furnace use the best available estimate(s) of 

the parameter(s), based on all available process data or 

data used for accounting purposes, such as purchase 

records. 
163

(b) For missing data on the mass fractions of 

carbonate-based minerals in the carbonate-based raw 

materials assume that the mass fraction of each carbonate 

based mineral is 1.0. 

§98.146 Data reporting requirements. 

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

each annual report must contain the information specified 

in paragraphs (a) and (b) of this section, as applicable. 

(a) If a CEMS is used to measure CO2 emissions, then 

you must report under this subpart the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology and the following information specified in 

paragraphs (a)(1) and (a)(2) of this section: 

(1) Annual quantity of each carbonate-based raw 

material charged to each continuous glass melting furnace 

and for all furnaces combined (tons). 

(2) Annual quantity of glass produced by each glass 

melting furnace and by all furnaces combined (tons). 

(b) If a CEMS is not used to determine CO2 emissions 

from continuous glass melting furnaces, and process CO2

emissions are calculated according to the procedures 

specified in §98.143(b), then you must report the following 

information as specified in paragraphs (b)(1) through 

(b)(9) of this section: 

Deleted: 7
164

(1) Annual process emissions of CO2 (metric tons) for 

each continuous glass melting furnace and for all furnaces 

combined. 

(2) Annual quantity of each carbonate-based raw 

material charged (tons) to each continuous glass melting 

furnace and for all furnaces combined. 

(3) Annual quantity of glass produced (tons) from 

each continuous glass melting furnace and from all furnaces 

combined. 

(4) Carbonate-based mineral mass fraction 

(percentage, expressed as a decimal) for each carbonatebased raw material charged to a continuous glass melting 

furnace. 

(5) Results of all tests used to verify the 

carbonate-based mineral mass fraction for each carbonatebased raw material charged to a continuous glass melting 

furnace, as specified in paragraphs (b)(5)(i) through 

(b)(5)(iii) of this section. 

(i) Date of test. 

(ii) Method(s) and any variations used in the 

analyses. 

(iii) Mass fraction of each sample analyzed. 
165

(6) The fraction of calcination achieved for each 

carbonate-based raw material, if a value other than 1.0 is 

used to calculate process mass emissions of CO2. 

(7) Method used to determine fraction of calcination. 

(8) Total number of continuous glass melting 

furnaces. 

(9) The number of times in the reporting year that 

missing data procedures were followed to measure monthly 

quantities of carbonate-based raw materials or mass 

fraction of the carbonate-based minerals for any continuous 

glass melting furnace (months). 

§98.147 Records that must be retained.

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

you must retain the records listed in paragraphs (a), (b), 

and (c) of this section. 

(a) If a CEMS is used to measure emissions, then you 

must retain the records required under §98.37 for the Tier 

4 Calculation Methodology and the following information 

specified in paragraphs (a)(1) and (a)(2) of this section: 

(1) Monthly glass production rate for each continuous 

glass melting furnace (tons). 

(2) Monthly amount of each carbonate-based raw 

material charged to each continuous glass melting furnace 

(tons). 

Deleted: (percentage, 

expressed as a decimal)

Deleted: any continuous glass 

melting furnace 
166

(b) If process CO2 emissions are calculated according 

to the procedures specified in §98.143(b), you must retain 

the records in paragraphs (b)(1) through (b)(5) of this 

section. 

(1) Monthly glass production rate for each continuous 

glass melting furnace (metric tons). 

(2) Monthly amount of each carbonate-based raw 

material charged to each continuous glass melting furnace 

(metric tons). 

(3) Data on carbonate-based mineral mass fractions 

provided by the raw material supplier for all raw materials 

consumed annually and included in calculating process 

emissions in Equation N-1 of this subpart. 

(4) Results of all tests used to verify the 

carbonate-based mineral mass fraction for each carbonatebased raw material charged to a continuous glass melting 

furnace, including the data specified in paragraphs 

(b)(4)(i) through (b)(4)(v) of this section. 

(i) Date of test. 

(ii) Method(s), and any variations of the methods, 

used in the analyses. 

(iii) Mass fraction of each sample analyzed. 

(iv) Relevant calibration data for the instrument(s) 

used in the analyses. 
167

(v) Name and address of laboratory that conducted the 

tests. 

(5) The fraction of calcination achieved for each 

carbonate-based raw material (percentage, expressed as a 

decimal), if a value other than 1.0 is used to calculate 

process mass emissions of CO2. 

(c) All other documentation used to support the 

reported GHG emissions. 

§98.148 Definitions.

All terms used in this subpart have the same meaning 

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

Table N-1 of Subpart N—CO2 Emission Factors for CarbonateBased Raw Materials 

Carbonate-Based Raw Material – Mineral CO2 Emission Factora

Limestone – CaCO3 0.440 

Dolomite – CaMg(CO3)2 0.477 

Sodium carbonate/soda ash – Na2CO3 0.415 

Barium carbonate – BaCO3 0.223

Potassium carbonate - K2CO3 0.318

a Emission factors in units of metric tons of CO2 emitted per metric 

ton of carbonate-based raw material charged to the furnace.

Subpart O—HCFC-22 Production and HFC-23 Destruction 

§98.150 Definition of the source category.

The HCFC-22 production and HFC-23 destruction source 

category consists of HCFC-22 production processes and HFC23 destruction processes. 

(a) An HCFC-22 production process produces HCFC-22 

(chlorodifluoromethane, or CHClF2) from chloroform (CHCl3) 

and hydrogen fluoride (HF). 
168

(b) An HFC-23 destruction process is any process in 

which HFC-23 undergoes destruction. An HFC-23 destruction 

process may or may not be co-located with an HCFC-22 

production process at the same facility. 

§98.151 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a HCFC-22 production or HFC-23 

destruction process and the facility meets the requirements 

of either §98.2(a)(1) or (a)(2). 

§98.152 GHGs to report.

(a) You must report under subpart C of this part 

(General Stationary Fuel Combustion Sources) the emissions 

of CO2, CH4, and N2O from each stationary combustion unit 

following the requirements of subpart C. 

(b) You must report HFC-23 emissions from HCFC-22 

production processes and HFC-23 destruction processes. 

§98.153 Calculating GHG emissions.

(a) The mass of HFC-23 generated from each HCFC-22 

production process shall be estimated by using one of two 

methods, as applicable: 

(1) Where the mass flow of the combined stream of 

HFC-23 and another reaction product (e.g., HCl) is 

measured, multiply the weekly (or more frequent) HFC-23 

concentration measurement (which may be the average of more 
169

frequent concentration measurements) by the weekly (or more 

frequent) mass flow of the combined stream of HFC-23 and 

the other product. To estimate annual HFC-23 production, 

sum the weekly (or more frequent) estimates of the 

quantities of HFC-23 produced over the year. This 

calculation is summarized in Equation O-1 of this section: 

∑=

−

=

n

p

Fp G c

1

3

23 23 * *10 (Eq. O-1) 

Where: 

G23 = Mass of HFC-23 generated annually (metric 

tons). 

c23 = Fraction HFC-23 by weight in HFC-23/other 

product stream. 

Fp = Mass flow of HFC-23/other product stream during 

the period p (kg). 

p = Period over which mass flows and concentrations 

are measured. 

n = Number of concentration and flow measurement 

periods for the year. 

10-3 = Conversion factor from kilograms to metric tons. 

(2) Where the mass of only a reaction product other 

than HFC-23 (either HCFC-22 or HCl) is measured, multiply 

the ratio of the weekly (or more frequent) measurement of 

the HFC-23 concentration and the weekly (or more frequent) 

measurement of the other product concentration by the 

weekly (or more frequent) mass produced of the other 

product. To estimate annual HFC-23 production, sum the 

weekly (or more frequent) estimates of the quantities of 
170

HFC-23 produced over the year. This calculation is 

summarized in Equation O-2 of this section, assuming that 

the other product is HCFC-22. If the other product is HCl, 

HCl may be substituted for HCFC-22 in Equations O-2 and O-3 

of this section. 

3

22

1 22

23

23 * *10 −

=

∑ 















= P

c

c

G

n

p

(Eq. O-2) 

Where: 

G23 = Mass of HFC-23 generated annually (metric 

tons). 

c23 = Fraction HFC-23 by weight in HCFC-22/HFC-23 

stream. 

c22 = Fraction HCFC-22 by weight in HCFC-22/HFC-23 

stream. 

P22 = Mass of HCFC-22 produced over the period p 

(kg), calculated using Equation O-3 of this 

section. 

p = Period over which masses and concentrations are 

measured. 

n = Number of concentration and mass measurement 

periods for the year. 

10-3 = Conversion factor from kilograms to metric 

tons. 

(b) The mass of HCFC-22 produced over the period p 

shall be estimated by using Equation O-3 of this section: 

*( ) P22 = LF O22 −U22 (Eq. O-3) 

Where: 

P22 = Mass of HCFC-22 produced over the period p (kg). 

O22 = mass of HCFC-22 that is measured coming out of the 

Production process over the period p (kg). 

U22 = Mass of used HCFC-22 that is added to the 

production process upstream of the output 

measurement over the period p (kg). 
171

LF = Factor to account for the loss of HCFC-22 upstream 

of the measurement. The value for LF shall be 

determined pursuant to §98.154(e). 

(c) For HCFC-22 production facilities that do not use 

a thermal oxidizer or that have a thermal oxidizer that is 

not directly connected to the HCFC-22 production equipment, 

HFC-23 emissions shall be estimated using Equation O-4 of 

this section: 

( ) 23 23 23 23 23 23 E = G − S + OD + D + I (Eq. O-4) 

Where: 

E23 = Mass of HFC-23 emitted annually (metric tons). 

G23 = Mass of HFC-23 generated annually (metric 

tons). 

S23 = Mass of HFC-23 sent off site for sale annually 

(metric tons). 

OD23 = Mass of HFC-23 sent off site for destruction 

(metric tons). 

D23 = Mass of HFC-23 destroyed on site (metric tons). 

I23 = Increase in HFC-23 inventory = HFC-23 in 

storage at end of year – HFC-23 in storage at 

beginning of year (metric tons). 

(d) For HCFC-22 production facilities that use a 

thermal oxidizer connected to the HCFC-22 production 

equipment, HFC-23 emissions shall be estimated using 

Equation O-5 of this section: 

E23 = EL + EPV + ED (Eq. O-5) 

Where: 

E23 = Mass of HFC-23 emitted annually (metric tons). 

EL = Mass of HFC-23 emitted annually from equipment 

leaks, calculated using Equation O-6 of this 

section (metric tons). 
172

EPV = Mass of HFC-23 emitted annually from process 

vents, calculated using Equation O-7 of this 

section (metric tons). 

ED = Mass of HFC-23 emitted annually from thermal 

oxidizer (metric tons), calculated using 

Equation O-8 of this section. 

(1) The mass of HFC-23 emitted annually from 

equipment leaks (for use in Equation O-5 of this section) 

shall be estimated by using Equation O-6 of this section: 

( )

3

1

23 * * * *10−

=

= ∑∑ +

n

p

Gt Gt Lt Lt

t

ELc F N F N (Eq. O-6) 

Where: 

EL = Mass of HFC-23 emitted annually from equipment 

leaks (metric tons). 

c23 = Fraction HFC-23 by weight in the stream(s) in the 

equipment. 

FGt = The applicable leak rate specified in Table O-1 

of this subpart for each source of equipment type 

and service t with a screening value greater than 

or equal to 10,000 ppmv (kg/hr/source). 

NGt = The number of sources of equipment type and 

service t with screening values greater than or 

equal to 10,000 ppmv as determined according to 

§98.154(i). 

FLt = The applicable leak rate specified in Table O-1 

of this subpart for each source of equipment type 

and service t with a screening value of less than 

10,000 ppmv (kg/hr/source). 

NLt = The number of sources of equipment type and 

service t with screening values less than 10,000 

ppmv as determined according to §98.154(j). 

p = One hour. 

n = Number of hours during the year during which 

equipment contained HFC-23. 

t = Equipment type and service as specified in Table 

O-1 of this subpart .
173

10-3 = Factor converting kg to metric tons. 

(2) The mass of HFC-23 emitted annually from process 

vents (for use in Equation O-5 of this section) shall be 

estimated by using Equation O-7 of this section: 

3

1

* * *10−

=

∑ 















= p

n

p T

p

PV T

l

PR

PR

E ER (Eq. O-7) 

Where: 

EPV = Mass of HFC-23 emitted annually from process 

vents (metric tons). 

ERT = The HFC-23 emission rate from the process vents 

during the period of the most recent test 

(kg/hr). 

PRp = The HCFC-22 production rate during the period p 

(kg/hr). 

PRT = The HCFC-22 production rate during the most 

recent test period (kg/hr). 

lp = The length of the period p (hours). 

10-3 = Factor converting kg to metric tons. 

n = The number of periods in a year. 

(3) The total mass of HFC-23 emitted from destruction 

devices shall be estimated by using Equation O-8 of this 

section: 

E D = FD − D23 (Eq. O-8) 

Where: 

ED = Mass of HFC-23 emitted annually from the 

destruction device (metric tons). 

FD = Mass of HFC-23 fed into the destruction device 

annually (metric tons). 

D23 = Mass of HFC-23 destroyed annually (metric tons). 
174

(4) For facilities that destroy HFC-23, the total 

mass of HFC-23 destroyed shall be estimated by using 

Equation O-9 of this section: 

D23 = FD *DE (Eq. O-9) 

Where: 

D23 = Mass of HFC-23 destroyed annually (metric 

tons). 

FD = Mass of HFC-23 fed into the destruction device 

annually (metric tons). 

DE = Destruction Efficiency of the destruction 

device (fraction). 

§98.154 Monitoring and QA/QC requirements. 

These requirements apply to measurements that are 

reported under this subpart or that are used to estimate 

reported quantities pursuant to §98.153. 

(a) The concentrations (fractions by weight) of HFC23 and HCFC-22 in the product stream shall be measured at 

least weekly using equipment and methods (e.g., gas 

chromatography) with an accuracy and precision of 5 percent 

or better at the concentrations of the process samples. 

(b) The mass flow of the product stream containing 

the HFC-23 shall be measured at least weekly using weigh 

scales, flowmeters, or a combination of volumetric and 

density measurements with an accuracy and precision of 1.0 

percent of full scale or better. 
175

(c) The mass of HCFC-22 or HCl coming out of the 

production process shall be measured at least weekly using 

weigh scales, flowmeters, or a combination of volumetric 

and density measurements with an accuracy and precision of 

1.0 percent of full scale or better. 

(d) The mass of any used HCFC-22 added back into the 

production process upstream of the output measurement in 

paragraph (c) of this section shall be measured (when being 

added) using flowmeters, weigh scales, or a combination of 

volumetric and density measurements with an accuracy and 

precision of 1.0 percent of full scale or better. If the 

mass in paragraph (c) of this section is measured by 

weighing containers that include returned heels as well as 

newly produced fluorinated GHGs, the returned heels shall 

be considered used fluorinated HCFC-22 for purposes of this 

paragraph (d) of this section and §98.153(b). 

(e) The loss factor LF in Equation O-3 of this 

subpart for the mass of HCFC-22 produced shall have the 

value 1.015 or another value that can be demonstrated, to 

the satisfaction of the Administrator, to account for 

losses of HCFC-22 between the reactor and the point of 

measurement at the facility where production is being 

estimated. 
176

(f) The mass of HFC-23 sent off site for sale shall 

be measured at least weekly (when being packaged) using 

flowmeters, weigh scales, or a combination of volumetric 

and density measurements with an accuracy and precision of 

1.0 percent of full scale or better. 

(g) The mass of HFC-23 sent off site for destruction 

shall be measured at least weekly (when being packaged) 

using flowmeters, weigh scales, or a combination of 

volumetric and density measurements with an accuracy and 

precision of 1.0 percent of full scale or better. If the 

measured mass includes more than trace concentrations of 

materials other than HFC-23, the concentration of the 

fluorinated GHG shall be measured at least weekly using 

equipment and methods (e.g., gas chromatography) with an 

accuracy and precision of 5 percent or better at the 

concentrations of the process samples. This concentration 

(mass fraction) shall be multiplied by the mass measurement 

to obtain the mass of the HFC-23 sent to another facility 

for destruction. 

(h) The masses of HFC-23 in storage at the beginning 

and end of the year shall be measured using flowmeters, 

weigh scales, or a combination of volumetric and density 

measurements with an accuracy and precision of 1.0 percent 

of full scale or better. 
177

(i) The number of sources of equipment type t with 

screening values greater than or equal to 10,000 ppmv shall 

be determined using EPA Method 21 at 40 CFR part 60, 

appendix A-7, and defining a leak as follows: 

(1) A leak source that could emit HFC-23, and 

(2) A leak source at whose surface a concentration of 

fluorocarbons equal to or greater than 10,000 ppm is 

measured. 

(j) The number of sources of equipment type t with 

screening values less than 10,000 ppmv shall be the 

difference between the number of leak sources of equipment 

type t that could emit HFC-23 and the number of sources of 

equipment type t with screening values greater than or 

equal to 10,000 ppmv as determined under paragraph (h) of 

this section. 

(k) The mass of HFC-23 emitted from process vents 

shall be estimated at least monthly by incorporating the 

results of the most recent emissions test into Equation O-7

of this subpart. HCFC-22 production facilities that use a 

destruction device connected to the HCFC-22 production 

equipment shall conduct emissions tests at process vents at 

least once every five years or after significant changes to 

the process. Emissions tests shall be conducted in 

accordance with EPA Method 18 at 40 CFR part 60, appendix 

Deleted: 6

Deleted: thermal oxidizer
178

A-6, under conditions that are typical for the production 

process at the facility. The sensitivity of the tests 

shall be sufficient to detect an emission rate that would 

result in annual emissions of 200 kg of HFC-23 if sustained 

over one year. 

(l) For purposes of Equation O-9 of this subpart, the 

destruction efficiency must be equated to the destruction 

efficiency determined during a new or previous performance 

test of the destruction device. HFC-23 destruction 

facilities shall conduct annual measurements of HFC-23 

concentrations at the outlet of the destruction device in 

accordance with EPA Method 18 at 40 CFR part 60, appendix 

A-6. Three samples shall be taken under conditions that 

are typical for the production process and destruction 

device at the facility, and the average concentration of 

HFC-23 shall be determined. The sensitivity of the 

concentration measurement shall be sufficient to detect an 

outlet concentration equal to or less than the outlet 

concentration determined in the destruction efficiency 

performance test. If the concentration measurement 

indicates that the HFC-23 concentration is less than or 

equal to that measured during the performance test that is 

the basis for the destruction efficiency, continue to use 

the previously determined destruction efficiency. If the 

Deleted: thermal oxidizer 
179

concentration measurement indicates that the HFC-23 

concentration is greater than that measured during the 

performance test that is the basis for the destruction 

efficiency, facilities shall either: 

(1) Substitute the higher HFC-23 concentration for 

that measured during the destruction efficiency performance 

test and calculate a new destruction efficiency, or 

(2) Estimate the mass emissions of HFC-23 from the 

destruction device based on the measured HFC-23 

concentration and volumetric flow rate determined by 

measurement of volumetric flow rate using EPA Method 2, 2A, 

2C,2D, or 2F at 40 CFR part 60, appendix A-1, or Method 26 

at 40 CFR part 60, appendix A-2. Determine the mass rate 

of HFC-23 into the destruction device by measuring the HFC23 concentration and volumetric flow rate at the inlet or 

by a metering device for HFC-23 sent to the device. 

Determine a new destruction efficiency based on the mass 

flow rate of HFC-23 into and out of the destruction device. 

(m) HCFC-22 production facilities shall account for 

HFC-23 generation and emissions that occur as a result of 

startups, shutdowns, and malfunctions, either recording 

HFC-23 generation and emissions during these events, or 

documenting that these events do not result in significant 

HFC-23 generation and/or emissions. 
180

(n) The mass of HFC-23 fed into the destruction 

device shall be measured at least weekly using flowmeters, 

weigh scales, or a combination of volumetric and density 

measurements with an accuracy and precision of 1.0 percent 

of full scale or better. If the measured mass includes 

more than trace concentrations of materials other than HFC23, the concentrations of the HFC-23 shall be measured at 

least weekly using equipment and methods (e.g., gas 

chromatography) with an accuracy and precision of 5 percent 

or better at the concentrations of the process samples. 

This concentration (mass fraction) shall be multiplied by 

the mass measurement to obtain the mass of the HFC-23 

destroyed. 

(o) In their estimates of the mass of HFC-23 

destroyed, HFC-23 destruction facilities shall account for 

any temporary reductions in the destruction efficiency that 

result from any startups, shutdowns, or malfunctions of the 

destruction device, including departures from the operating 

conditions defined in state or local permitting 

requirements and/or destruction device manufacturer 

specifications. 

(p) Calibrate all flow meters, weigh scales, and 

combinations of volumetric and density measures using NISTtraceable standards and suitable methods published by a 

Deleted: oxidizer 
181

consensus standards organization (e.g., ASTM, ASME, ISO, or 

others). Recalibrate all flow meters, weigh scales, and 

combinations of volumetric and density measures at the 

minimum frequency specified by the manufacturer. 

(q) All gas chromatographs used to determine the 

concentration of HFC-23 in process streams shall be 

calibrated at least monthly through analysis of certified 

standards (or of calibration gases prepared from a highconcentration certified standard using a gas dilution 

system that meets the requirements specified in Method 205 

at 40 CFR part 51, appendix M) with known HFC-23 

concentrations that are in the same range (fractions by 

mass) as the process samples. 

§98.155 Procedures for estimating missing data. 

(a) A complete record of all measured parameters used 

in the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable (e.g., if a meter malfunctions during unit 

operation or if a required process sample is not taken), a 

substitute data value for the missing parameter shall be 

used in the calculations, according to the following 

requirements: 

(1) For each missing value of the HFC-23 or HCFC-22 

concentration, the substitute data value shall be the 
182

arithmetic average of the quality-assured values of that 

parameter immediately preceding and immediately following 

the missing data incident. If, for a particular parameter, 

no quality-assured data are available prior to the missing 

data incident, the substitute data value shall be the first 

quality-assured value obtained after the missing data 

period. 

(2) For each missing value of the product stream mass 

flow or product mass, the substitute value of that 

parameter shall be a secondary product measurement where 

such a measurement is available. If that measurement is 

taken significantly downstream of the usual mass flow or 

mass measurement (e.g., at the shipping dock rather than 

near the reactor), the measurement shall be multiplied by 

1.015 to compensate for losses. Where a secondary mass 

measurement is not available, the substitute value of the 

parameter shall be an estimate based on a related 

parameter. For example, if a flowmeter measuring the mass 

fed into a destruction device is rendered inoperable, then 

the mass fed into the destruction device may be estimated 

using the production rate and the previously observed 

relationship between the production rate and the mass flow 

rate into the destruction device. 

§98.156 Data reporting requirements.
183

(a) In addition to the information required by 

§98.3(c), the HCFC-22 production facility shall report the 

following information at the facility level: 

(1) Annual mass of HCFC-22 produced in metric tons. 

(2) Loss Factor used to account for the loss of HCFC– 

22 upstream of the measurement. 

(3) Annual mass of reactants fed into the process in 

metric tons of reactant. 

(4) The mass (in metric tons) of materials other than 

HCFC-22 and HFC-23 (i.e., unreacted reactants, HCl and 

other by-products) that occur in more than trace 

concentrations and that are permanently removed from the 

process. 

(5) The method for tracking startups, shutdowns, and 

malfunctions and HFC-23 generation/emissions during these 

events. 

(6) The names and addresses of facilities to which 

any HFC-23 was sent for destruction, and the quantities of 

HFC-23 (metric tons) sent to each. 

(7) Annual mass of the HFC-23 generated in metric 

tons. 

(8) Annual mass of any HFC-23 sent off site for sale 

in metric tons. 
184

(9) Annual mass of any HFC-23 sent off site for 

destruction in metric tons. 

(10) Mass of HFC-23 in storage at the beginning and 

end of the year, in metric tons. 

(11) Annual mass of HFC-23 emitted in metric tons. 

(12) Annual mass of HFC-23 emitted from equipment 

leaks in metric tons. 

(13) Annual mass of HFC-23 emitted from process vents 

in metric tons. 

(b) In addition to the information required by 

§98.3(c), facilities that destroy HFC-23 shall report the 

following for each HFC-23 destruction process: 

(1) Annual mass of HFC-23 fed into the destruction 

device. 

(2) Annual mass of HFC-23 destroyed. 

(3) Annual mass of HFC-23 emitted from the 

destruction device. 

(c) Each HFC-23 destruction facility shall report the 

concentration (mass fraction) of HFC-23 measured at the 

outlet of the destruction device during the facility’s 

annual HFC-23 concentration measurements at the outlet of 

the device.

(d) If the HFC-23 concentration measured pursuant to 

§98.154(l) is greater than that measured during the 

Deleted: thermal oxidizer

Deleted: thermal oxidizer

Deleted: results of 

Deleted: destruction 

Deleted: , including:
185

performance test that is the basis for the destruction 

efficiency(DE), the facility shall report the revised 

destruction efficiency calculated under §98.154(l) and the 

values used to calculate it, specifying whether 

§98.154(l)(1) or §98.154(l)(2) has been used for the 

calculation. Specifically, the facility shall report the 

following: 

(1) Flow rate of HFC-23 being fed into the 

destruction device in kg/hr. 

(2) Concentration (mass fraction) of HFC-23 at the 

outlet of the destruction device. 

(3) Flow rate at the outlet of the destruction device 

in kg/hr. 

(4) Emission rate (in kg/hr) calculated from 

paragraphs (d)(2) and (d)(3) of this section.

(5) Destruction efficiency (DE) calculated from 

paragraphs (d)(1) and (d)(4) of this section.

(e) By March 31, 2011 or within 60 days of commencing 

HFC-23 destruction, HFC-23 destruction facilities shall 

submit a one-time report including the following 

information for each destruction process: 

(1) Destruction efficiency (DE). 

(2) The methods used to determine destruction 

efficiency. 

Deleted: d

Deleted: c

Deleted: in kg/hr

Deleted: the 
186

(3) The methods used to record the mass of HFC-23 

destroyed. 

(4) The name of other relevant federal or state 

regulations that may apply to the destruction process. 

(5) If any changes are made that affect HFC-23 

destruction efficiency or the methods used to record volume 

destroyed, then these changes must be reflected in a 

revision to this report. The revised report must be 

submitted to EPA within 60 days of the change. 

§98.157 Records that must be retained.

(a) In addition to the data required by §98.3(g), 

HCFC-22 production facilities shall retain the following 

records: 

(1) The data used to estimate HFC-23 emissions. 

(2) Records documenting the initial and periodic 

calibration of the gas chromatographs, weigh scales, 

volumetric and density measurements, and flowmeters used to 

measure the quantities reported under this rule, including 

the industry standards or manufacturer directions used for 

calibration pursuant to §98.154(p) and (q). 

(b) In addition to the data required by §98.3(g), the 

HFC-23 destruction facilities shall retain the following 

records: 
187

(1) Records documenting their one-time and annual 

reports in §98.156(b) through (e). 

(2) Records documenting the initial and periodic 

calibration of the gas chromatographs, weigh scales, 

volumetric and density measurements, and flowmeters used to 

measure the quantities reported under this subpart, 

including the industry standard practice or manufacturer 

directions used for calibration pursuant to §98.154(p) and 

(q). 

§98.158 Definitions.

All terms used in this subpart have the same meaning 

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

Table O-1 of Subpart O–Emission Factors for Equipment Leaks 

Emission Factor (kg/hr/source) 

Equipment Type Service ≥10,000 ppmv <10,000 ppmv 

Valves Gas 0.0782 0.000131 

Valves Light liquid 0.0892 0.000165 

Pump seals Light liquid 0.243 0.00187 

Compressor seals Gas 1.608 0.0894 

Pressure relief 

valves 

Gas 1.691 0.0447 

Connectors All 0.113 0.0000810 

Open-ended lines All 0.01195 0.00150 

Subpart P—Hydrogen Production 

§98.160 Definition of the source category.

(a) A hydrogen production source category consists of 

facilities that produce hydrogen gas sold as a product to 

other entities. 

Deleted: d
188

(b) This source category comprises process units that 

produce hydrogen by reforming, gasification, oxidation, 

reaction, or other transformations of feedstocks. 

(c) This source category includes merchant hydrogen 

production facilities located within another facility if 

they are not owned by, or under the direct control of, the 

other facility’s owner and operator. 

§98.161 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a hydrogen production process and 

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

or (a)(2). 

§98.162 GHGs to report.

You must report: 

(a) CO2 emissions from each hydrogen production 

process unit. 

(b) [Reserved]

(c) CO2, CH4, and N2O emissions from each stationary 

combustion unit other than hydrogen production process 

units. You must calculate and report these emissions under 

subpart C of this part (General Stationary Fuel Combustion 

Sources) by following the requirements of subpart C. 

(d) For CO2 collected and transferred off site, you 

must follow the requirements of subpart PP of this part. 

Deleted: a petroleum refinery 

Deleted: refinery 

Deleted: process 

Deleted: CO2, CH4 and N2O 

combustion emissions from 

each hydrogen production 

process unit. You must 

calculate and report these 

combustion emissions under 

subpart C of this part 

(General Stationary Fuel 

Combustion Sources) by 

following the requirements 

of subpart C.
189

§98.163 Calculating GHG emissions.

You must calculate and report the annual CO2 emissions 

from each hydrogen production process unit using the 

procedures specified in either paragraph (a) or (b) of this 

section. 

(a) Continuous Emissions Montoring Systems (CEMS). 

Calculate and report under this subpart the CO2 emissions by 

operating and maintaining CEMS according to the Tier 4 

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

associated requirements for Tier 4 in subpart C of this 

part (General Stationary Fuel Combustion Sources). 

(b) Fuel and feedstock material balance approach.

Calculate and report CO2 emissions as the sum of the annual 

emissions associated with each fuel and feedstock used for 

hydrogen production by following paragraphs (b)(1) through 

(b)(3) of this section. 

(1) Gaseous fuel and feedstock. You must calculate 

the annual CO2 emissions from each gaseous fuel and 

feedstock according to Equation P-1 of this section: 

* ) * 0.001

12

44 (

1

2 MVC

MW CO Fdstk n CCn

k

n

= ∑ ∗ ∗

=

(Eq. P-1) 

Where: 

CO2 = Annual CO2 emissions arising from fuel and 

feedstock consumption (metric tons/yr). 

Fdstkn = Volume of the gaseous fuel and feedstock used 

in month n (scf (at standard conditions of 

Deleted: process 

Deleted: process 

Deleted: process 

Deleted: process 

Deleted: process 
190

68 °F and atmospheric pressure) of fuel and 

feedstock). 

CCn = Average carbon content of the gaseous fuel and 

feedstock, from the results of one or more 

analyses for month n (kg carbon per kg of 

fuel and feedstock). 

MW = Molecular weight of the gaseous fuel and 

feedstock (kg/kg-mole). 

MVC = Molar volume conversion factor (849.5 scf per 

kg-mole at standard conditions). 

k = Months in the year. 

44/12 = Ratio of molecular weights, CO2 to carbon. 

0.001 = Conversion factor from kg to metric tons. 

(2) Liquid fuel and feedstock. You must calculate 

the annual CO2 emissions from each liquid fuel and feedstock 

according to Equation P-2 of this section: 

)* 0.001

12

44 (

1

2 n n

k

n

CO = ∑ ∗ Fdstk ∗CC

=

 (Eq. P-2) 

Where: 

CO2 = Annual CO2 emissions arising from fuel and 

feedstock consumption (metric tons/yr). 

Fdstkn = Volume of the liquid fuel and feedstock used in 

month n (gallons of fuel and feedstock). 

CCn = Average carbon content of the liquid fuel and 

feedstock, from the results of one or more 

analyses for month n (kg carbon per gallon of 

fuel and feedstock). 

k = Months in the year. 

44/12 = Ratio of molecular weights, CO2 to carbon. 

0.001 = Conversion factor from kg to metric tons. 

Deleted: process 
191

(3) Solid fuel and feedstock. You must calculate the 

annual CO2 emissions from each solid fuel and feedstock 

according to Equation P-3 of this section: 

)* 0.001

12

44 (

1

2 n n

k

n

CO = ∑ ∗ Fdstk ∗CC

=

(Eq.P-3) 

Where: 

CO2 = Annual CO2 emissions from fuel and feedstock 

consumption in metric tons per month (metric 

tons/yr). 

Fdstkn = Mass of solid fuel and feedstock used in month 

n (kg of fuel and feedstock). 

CCn = Average carbon content of the solid fuel and 

feedstock, from the results of one or more 

analyses for month n (kg carbon per kg of fuel 

and feedstock). 

k = Months in the year. 

44/12 = Ratio of molecular weights, CO2 to carbon. 

0.001 = Conversion factor from kg to metric tons. 

(c) If GHG emissions from a hydrogen production 

process unit are vented through the same stack as any 

combustion unit or process equipment that reports CO2

emissions using a CEMS that complies with the Tier 4 

Calculation Methodology in subpart C of this part (General 

Stationary Fuel Combustion Sources), then the calculation 

methodology in paragraph (b) of this section shall not be 

used to calculate process emissions. The owner or operator 

shall report under this subpart the combined stack 

emissions according to the Tier 4 Calculation Methodology 

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

Deleted: process 
192

in subpart C of this part (General Stationary Fuel 

Combustion Sources). 

§98.164 Monitoring and QA/QC requirements.

The GHG emissions data for hydrogen production process 

units must be quality-assured as specified in paragraphs 

(a) or (b) of this section, as appropriate for each process 

unit: 

(a) If a CEMS is used to measure GHG emissions, then 

the facility must comply with the monitoring and QA/QC 

procedures specified in §98.34(c). 

(b) If a CEMS is not used to measure GHG emissions, 

then you must: 

(1) Calibrate all oil and gas flow meters (except for 

gas billing meters), solids weighing equipment, and oil 

tank drop measurements (if used to determine liquid fuel 

and feedstock use volume) according to the calibration 

accuracy requirements in §98.3(i) of this part. 

(2) Determine the carbon content and the molecular 

weight annually of standard gaseous hydrocarbon fuels and 

feedstocks having consistent composition (e.g., natural 

gas). For other gaseous fuels and feedstocks (e.g., biogas, 

refinery gas, or process gas), weekly sampling and analysis 

is required to determine the carbon content and molecular 

weight of the fuel and feedstock. 
193

(3) Determine the carbon content of fuel oil, 

naphtha, and other liquid fuels and feedstocks at least 

monthly, except annually for standard liquid hydrocarbon 

fuels and feedstocks having consistent composition, or upon 

delivery for liquid fuels delivered by bulk transport 

(e.g., by truck or rail). 

(4) Determine the carbon content of coal, coke, and 

other solid fuels and feedstocks at least monthly, except 

annually for standard solid hydrocarbon fuels and 

feedstocks having consistent composition, or upon delivery 

for solid fuels delivered by bulk transport (e.g., by truck 

or rail). 

(5) You must use the following applicable methods to 

determine the carbon content for all fuels and feedstocks, 

and molecular weight of gaseous fuels and feedstocks. 

(i) ASTM D1945-03 Standard Test Method for Analysis 

of Natural Gas by Gas Chromatography (incorporated by 

reference, see §98.7). 

(ii) ASTM D1946-90 (Reapproved 2006), Standard 

Practice for Analysis of Reformed Gas by Gas Chromatography 

(incorporated by reference, see §98.7). 

(iii) ASTM D2013-07 Standard Practice of Preparing 

Coal Samples for Analysis (incorporated by reference, see 

§98.7). 
194

(iv) ASTM D2234/D2234M-07 Standard Practice for 

Collection of a Gross Sample of Coal (incorporated by 

reference, see §98.7). 

(v) ASTM D2597-94 (Reapproved 2004) Standard Test 

Method for Analysis of Demethanized Hydrocarbon Liquid 

Mixtures Containing Nitrogen and Carbon Dioxide by Gas 

Chromatography (incorporated by reference, see §98.7). 

(vi) ASTM D3176-89 (Reapproved 2002), Standard 

Practice for Ultimate Analysis of Coal and Coke 

(incorporated by reference, see §98.7). 

(vii) ASTM D3238-95 (Reapproved 2005), Standard Test 

Method for Calculation of Carbon Distribution and 

Structural Group Analysis of Petroleum Oils by the n-d-M 

Method (incorporated by reference, see §98.7). 

(viii) ASTM D4057-06 Standard Practice for Manual 

Sampling of Petroleum and Petroleum Products (incorporated 

by reference, see §98.7). 

(ix) ASTM D4177-95 (Reapproved 2005) Standard 

Practice for Automatic Sampling of Petroleum and Petroleum 

Products (incorporated by reference, see §98.7). 

(x) ASTM D5291-02 (Reapproved 2007), Standard Test 

Methods for Instrumental Determination of Carbon, Hydrogen, 

and Nitrogen in Petroleum Products and Lubricants 

(incorporated by reference, see §98.7). 
195

(xi) ASTM D5373-08 Standard Test Methods for 

Instrumental Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal (incorporated by 

reference, see §98.7). 

(xii) ASTM D6609-08 Standard Guide for Part-Stream 

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

(xiii) ASTM D6883-04 Standard Practice for Manual 

Sampling of Stationary Coal from Railroad Cars, Barges, 

Trucks, or Stockpiles (incorporated by reference, see 

§98.7). 

(xiv) ASTM D7430-08ae1 Standard Practice for 

Mechanical Sampling of Coal (incorporated by reference, see 

§98.7). 

(xv) ASTM UOP539-97 Refinery Gas Analysis by Gas 

Chromatography (incorporated by reference, see §98.7). 

(xvi) GPA 2261–00 Analysis for Natural Gas and 

Similar Gaseous Mixtures by Gas Chromatography 

(incorporated by reference, see §98.7). 

(xvii) ISO 3170: Petroleum Liquids -- Manual sampling 

– Third Edition (incorporated by reference, see §98.7). 

(xviii) ISO 3171: Petroleum Liquids -- Automatic 

pipeline sampling – Second Edition (incorporated by 

reference, see §98.7). 
196

(c) For units using the calculation methodologies 

described in this section, the records required under 

§98.3(g) must include both the company records and a 

detailed explanation of how company records are used to 

estimate the following: 

(1) Fuel and feedstock consumption, when solid fuel 

and feedstock is combusted and a CEMS is not used to 

measure GHG emissions. 

(2) Fossil fuel consumption, when, pursuant to 

§98.33(e), the owner or operator of a unit that uses CEMS 

to quantify CO2 emissions and that combusts both fossil and 

biogenic fuels separately reports the biogenic portion of 

the total annual CO2 emissions. 

(3) Sorbent usage, if the methodology in §98.33(d) is 

used to calculate CO2 emissions from sorbent. 

(d) The owner or operator must document the 

procedures used to ensure the accuracy of the estimates of 

fuel and feedstock usage and sorbent usage (as applicable) 

in paragraph (b) of this section, including, but not 

limited to, calibration of weighing equipment, fuel and 

feedstock flow meters, and other measurement devices. The 

estimated accuracy of measurements made with these devices 

must also be recorded, and the technical basis for these 

estimates must be provided. 
197

§98.165 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable (e.g., if a meter malfunctions during unit 

operation), a substitute data value for the missing 

parameter must be used in the calculations as specified in 

paragraphs (a), (b), and (c) of this section: 

(a) For each missing value of the monthly fuel and 

feedstock consumption, the substitute data value must be 

the best available estimate of the fuel and feedstock 

consumption, based on all available process data (e.g., 

hydrogen production, electrical load, and operating hours). 

You must document and keep records of the procedures used 

for all such estimates. 

(b) For each missing value of the carbon content or 

molecular weight of the fuel and feedstock, the substitute 

data value must be the arithmetic average of the qualityassured values of carbon contents or molecular weight of 

the fuel and feedstock immediately preceding and 

immediately following the missing data incident. If no 

quality-assured data on carbon contents or molecular weight 

of the fuel and feedstock are available prior to the 

missing data incident, the substitute data value must be 
198

the first quality-assured value for carbon contents or 

molecular weight of the fuel and feedstock obtained after 

the missing data period. You must document and keep 

records of the procedures used for all such estimates. 

(c) For missing CEMS data, you must use the missing 

data procedures in §98.35. 

§98.166 Data reporting requirements. 

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

each annual report must contain the information specified 

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

and (c) and (d): 

(a) If a CEMS is used to measure CO2 emissions, then 

you must report the relevant information required under 

§98.36 for the Tier 4 Calculation Methodology and the 

following information in this paragraph (a): 

(1) Unit identification number and annual CO2

emissions. 

(2) Annual quantity of hydrogen produced (metric 

tons) for each process unit and for all units combined. 

(3) Annual quantity of ammonia produced (metric 

tons), if applicable, for each process unit and for all 

units combined. 

Deleted: process 
199

(b) If a CEMS is not used to measure CO2 emissions, 

then you must report the following information for each 

hydrogen production process unit: 

(1) Unit identification number and annual CO2

emissions.

(2) Monthly consumption of each fuel and feedstock 

used for hydrogen production and its type (scf of gaseous 

fuels and feedstocks, gallons of liquid fuels and 

feedstocks, kg of solid fuels and feedstocks). 

(3) Annual quantity of hydrogen produced (metric 

tons). 

(4) Annual quantity of ammonia produced, if 

applicable (metric tons). 

(5) Monthly analyses of carbon content for each fuel 

and feedstock used in hydrogen production (kg carbon/kg of 

gaseous and solid fuels and feedstocks, (kg carbon per 

gallon of liquid fuels and feedstocks). 

(6) Monthly analyses of the molecular weight of 

gaseous fuels and feedstocks (kg/kg-mole) used, if any. 

(c) Quantity of CO2 collected and transferred off site 

in either gas, liquid, or solid forms, following the 

requirements of subpart PP of this part. 

Deleted: process 

Deleted: 

Deleted: Quarterly q

Deleted: (kg)
200

(d) Annual quantity of carbon other than CO2 collected 

and transferred off site in either gas, liquid, or solid 

forms (kg carbon). 

§98.167 Records that must be retained.

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

you must retain the records specified in paragraphs (a) 

through (b) of this section for each hydrogen production 

facility. 

(a) If a CEMS is used to measure CO2 emissions, then 

you must retain under this subpart the records required for 

the Tier 4 Calculation Methodology in §98.37. 

(b) If a CEMS is not used to measure CO2 emissions, 

then you must retain records of all analyses and 

calculations conducted as listed in §§98.166(b), (c), and 

(d). 

§98.168 Definitions.

All terms used in this subpart have the same meaning 

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

Subpart Q—Iron and Steel Production 

§98.170 Definition of the source category.

The iron and steel production source category includes 

facilities with any of the following processes: taconite 

iron ore processing, integrated iron and steel 

manufacturing, cokemaking not colocated with an integrated 
201

iron and steel manufacturing process, and electric arc 

furnace (EAF) steelmaking not colocated with an integrated 

iron and steel manufacturing process. Integrated iron and 

steel manufacturing means the production of steel from iron 

ore or iron ore pellets. At a minimum, an integrated iron 

and steel manufacturing process has a basic oxygen furnace 

for refining molten iron into steel. Each cokemaking 

process and EAF process located at a facility with an 

integrated iron and steel manufacturing process is part of 

the integrated iron and steel manufacturing facility. 

§98.171 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains an iron and steel production process 

and the facility meets the requirements of either 

§98.2(a)(1) or (2). 

§98.172 GHGs to report.

(a) You must report under subpart C of this part 

(General Stationary Fuel Combustion Sources) the emissions 

of CO2, CH4, and N2O from each stationary combustion unit 

following the requirements of subpart C except for flares. 

Stationary combustion units include, but are not limited 

to, by-product recovery coke oven battery combustion 

stacks, blast furnace stoves, boilers, process heaters, 

reheat furnaces, annealing furnaces, flame suppression, 
202

ladle reheaters, and other miscellaneous combustion 

sources. 

(b) You must report CO2 emissions from flares that 

burn blast furnace gas or coke oven gas according to the 

procedures in §98.253(b)(1) of subpart Y (Petroleum 

Refineries) of this part. When using the alternatives set 

forth in §98.253(b)(1)(ii)(B) and §98.253(b)(1)(iii)(C), 

you must use the default CO2 emission factors for coke oven 

gas and blast furnace gas from Table C-1 of subpart C in 

Equations Y-2 and Y-3 of subpart Y of this part. You must 

report CH4 and N2O emissions from flares according to the 

requirements in §98.33(c)(2) using the emission factors for 

coke oven gas and blast furnace gas in Table C-2 of subpart 

C of this part. 

(c) You must report process CO2 emissions from each 

taconite indurating furnace; basic oxygen furnace; nonrecovery coke oven battery combustion stack; coke pushing 

process; sinter process; EAF; decarburization vessel; and 

direct reduction furnace by following the procedures in 

this subpart. 

§98.173 Calculating GHG emissions.

You must calculate and report the annual process CO2

emissions from each taconite indurating furnace, basic 

oxygen furnace, non-recovery coke oven battery, sinter 

Deleted: except you 

Deleted: 1

Deleted: argon-oxygen 
203

process, EAF, decarburization vessel, and direct reduction 

furnace using the procedures in either paragraph (a) or (b) 

of this section. Calculate and report the annual process 

CO2 emissions from the coke pushing process according to 

paragraph (c) of this section. 

(a) Calculate and report under this subpart the 

process CO2 emissions by operating and maintaining CEMS 

according to the Tier 4 Calculation Methodology in 

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

subpart C of this part (General Stationary Fuel Combustion 

Sources). 

(b) Calculate and report under this subpart the 

process CO2 emissions using the procedure in paragraph 

(b)(1) or (b)(2) of this section. 

(1) Carbon mass balance method. Calculate the annual 

mass emissions of CO2 for the process as specified in 

paragraphs (b)(1)(i) through (b)(1)(vii) of this section. 

The calculations are based on the annual mass of inputs and 

outputs to the process and an annual analysis of the 

respective weight fraction of carbon as determined 

according to the procedures in §98.174(b). If you have a 

process input or output other than CO2 in the exhaust gas 

that contains carbon that is not included in Equations Q-1 

through Q-7 of this section, you must account for the 

Deleted: argon-oxygen 
204

carbon and mass rate of that process input or output in 

your calculations according to the procedures in 

§98.174(b)(5). 

(i) For taconite indurating furnaces, estimate CO2 

emissions using Equation Q-1 of this section. 

( ) ( )

( ) ( * ) * 0.001 ( ) * ( ) ( ) * ( ) ( ) * ( )]

*[( ) * ( ) * * * 0.001

12

44

2

l lf o p R

g gf

F C O C P C R C

MVC

MW CO Fs Csf F C

+ − −

= + +

(Eq. Q-1) 

Where: 

CO2 = Annual CO2 mass emissions from the taconite 

indurating furnace (metric tons). 

44/12 = Ratio of molecular weights, CO2 to carbon. 

(Fs) = Annual mass of the solid fuel combusted (metric 

tons). 

(Csf) = Carbon content of the solid fuel, from the fuel 

analysis (percent by weight, expressed as a 

decimal fraction, e.g., 95% = 0.95). 

(Fg) = Annual volume of the gaseous fuel combusted 

(scf). 

(Cgf) = Average carbon content of the gaseous fuel, from 

the fuel analysis results (kg C per kg of fuel). 

MW = Molecular weight of the gaseous fuel (kg/kgmole). 

MVC = Molar volume conversion factor (849.5 scf per 

kg-mole at standard conditions). 

0.001 = Conversion factor from kg to metric tons. 

(Fl) = Annual volume of the liquid fuel combusted 

(gallons). 

(Clf) = Carbon content of the liquid fuel, from the fuel 

analysis results (kg C per gallon of fuel). 

(O) = Annual mass of greenball (taconite) pellets fed 

to the furnace (metric tons). 
205

(C0) = Carbon content of the greenball (taconite) 

pellets, from the carbon analysis results 

(percent by weight, expressed as a decimal 

fraction). 

(P) = Annual mass of fired pellets produced by the 

furnace (metric tons). 

(Cp) = Carbon content of the fired pellets, from the 

carbon analysis results (percent by weight, 

expressed as a decimal fraction). 

(R) = Annual mass of air pollution control residue 

collected (metric tons). 

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results 

(percent by weight, expressed as a decimal 

fraction). 

(ii) For basic oxygen process furnaces, estimate CO2 

emissions using Equation Q-2 of this section. 

( ) ( ) ( ) ( ) ( ) ( )

( )*( ) ( ) *( ) ( ) *( ) ( )*( )]

*[ * * *

12

44

2

Carbon Steel Slag R

Iron Scrap Flux

Carbon C Steel C Slag C R C

CO Iron C Scrap C Flux C

+ − − −

= + +

(Eq. Q-2) 

Where: 

CO2 = Annual CO2 mass emissions from the basic 

oxygen furnace (metric tons). 

44/12 = Ratio of molecular weights, CO2 to carbon. 

(Iron) = Annual mass of molten iron charged to the 

furnace (metric tons). 

(CIron) = Carbon content of the molten iron, from the 

carbon analysis results (percent by weight, 

expressed as a decimal fraction). 

(Scrap) = Annual mass of ferrous scrap charged to the 

furnace (metric tons). 

(CScrap) = Carbon content of the ferrous scrap, from the 

carbon analysis results (percent by weight, 

expressed as a decimal fraction). 
206

(Flux) = Annual mass of flux materials (e.g., 

limestone, dolomite) charged to the furnace 

(metric tons). 

(CFlux) = Carbon content of the flux materials, from the 

carbon analysis results (percent by weight, 

expressed as a decimal fraction). 

(Carbon) = Annual mass of carbonaceous materials (e.g., 

coal, coke) charged to the furnace (metric 

tons). 

(CCarbon) = Carbon content of the carbonaceous materials, 

from the carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(Steel) = Annual mass of molten raw steel produced by 

the furnace (metric tons). 

(CSteel) = Carbon content of the steel, from the carbon 

analysis results (percent by weight, expressed 

as a decimal fraction). 

(Slag) = Annual mass of slag produced by the furnace 

(metric tons). 

(CSlag) = Carbon content of the slag, from the carbon 

analysis (percent by weight, expressed as a 

decimal fraction). 

(R) = Annual mass of air pollution control residue 

collected (metric tons). 

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results 

(percent by weight, expressed as a decimal 

fraction). 

(iii) For non-recovery coke oven batteries, estimate 

CO2 emissions using Equation Q-3 of this section. 

* [( ) * ( ) ( ) * ( ) ( ) * ( )]

12

44

2 CO = Coal CCoal − Coke CCoke − R CR (Eq. Q-3) 

Where: 

CO2 = Annual CO2 mass emissions from the nonrecovery coke oven battery (metric tons). 

44/12 = Ratio of molecular weights, CO2 to carbon. 
207

(Coal) = Annual mass of coal charged to the battery 

(metric tons). 

(CCoal) = Carbon content of the coal, from the carbon 

analysis results (percent by weight, expressed 

as a decimal fraction). 

(Coke) = Annual mass of coke produced by the battery 

(metric tons). 

(CCoke) = Carbon content of the coke, from the carbon 

analysis results (percent by weight, expressed 

as a decimal fraction). 

(R) = Annual mass of air pollution control residue 

collected (metric tons). 

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results 

(percent by weight, expressed as a decimal 

fraction). 

(iv) For sinter processes, estimate CO2 emissions 

using Equation Q-4 of this section. 

( ) ( )

( )* ( ) (Sinter) * ( ) ( ) * ( )]

* [ * * *0.001

12

44

Sinter

2

Feed R

g gf

Feed C C R C

MVC

MW CO F C

− −

= +

(Eq. Q-4) 

Where: 

CO2 = Annual CO2 mass emissions from the sinter 

process (metric tons). 

44/12 = Ratio of molecular weights, CO2 to carbon. 

(Fg) = Annual volume of the gaseous fuel combusted 

(scf). 

(Cgf) = Carbon content of the gaseous fuel, from the 

fuel analysis results (kg C per kg of fuel). 

MW = Molecular weight of the gaseous fuel (kg/kgmole). 

MVC = Molar volume conversion factor (849.5 scf per 

kg-mole at standard conditions). 

0.001 = Conversion factor from kg to metric tons. 
208

(Feed) = Annual mass of sinter feed material (metric 

tons). 

(CFeed) = Carbon content of the mixed sinter feed 

materials that form the bed entering the 

sintering machine, from the carbon analysis 

results (percent by weight, expressed as a 

decimal fraction). 

(Sinter) = Annual mass of sinter produced (metric tons). 

(CSinter) = Carbon content of the sinter pellets, from the 

carbon analysis results (percent by weight, 

expressed as a decimal fraction). 

(R) = Annual mass of air pollution control residue 

collected (metric tons). 

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results 

(percent by weight, expressed as a decimal 

fraction). 

(v) For EAFs, estimate CO2 emissions using Equation Q5 of this section. 

( ) ( ) ( ) ( ) ( )

( ) ( ) ( ) ( ) ( ) ( )

( Steel) ( ) ( Slag ) ( ) ( R)

f Electrode c

Iron Scrap

C Slag C R C

C Electrode C Carbon C Steel

CO Iron C Scrap C Flux

* * *

* * *

* [ * *

12

44

2

− −

+ + −

= + +

(Eq. Q-5) 

Where: 

CO2 = Annual CO2 mass emissions from the EAF (metric 

tons). 

44/12 = Ratio of molecular weights, CO2 to carbon. 

(Iron) = Annual mass of direct reduced iron (if any) 

charged to the furnace (metric tons). 

(CIron) = Carbon content of the direct reduced iron, 

from the carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(Scrap) = Annual mass of ferrous scrap charged to the 

furnace (metric tons). 
209

(CScrap) = Carbon content of the ferrous scrap, from the 

carbon analysis results (percent by weight, 

expressed as a decimal fraction). 

(Flux) = Annual mass of flux materials (e.g., 

limestone, dolomite) charged to the furnace 

(metric tons). 

(CFlux) = Carbon content of the flux materials, from the 

carbon analysis results (percent by weight, 

expressed as a decimal fraction). 

(Electrode) = Annual mass of carbon electrode consumed 

(metric tons). 

(CElectrode) = Carbon content of the carbon electrode, from 

the carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(Carbon) = Annual mass of carbonaceous materials (e.g., 

coal, coke) charged to the furnace (metric 

tons). 

(CCarbon) = Carbon content of the carbonaceous materials, 

from the carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(Steel) = Annual mass of molten raw steel produced by 

the furnace (metric tons). 

(CSteel) = Carbon content of the steel, from the carbon 

analysis results (percent by weight, 

expressed as a decimal fraction). 

(Slag) = Annual mass of slag produced by the furnace 

(metric tons). 

(CSlag) = Carbon content of the slag, from the carbon 

analysis results (percent by weight, 

expressed as a decimal fraction). 

(R) = Annual mass of air pollution control residue 

collected (metric tons). 

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results 

(percent by weight, expressed as a decimal 

fraction). 

(vi) For decarburization vessels, estimate CO2 

emissions using Equation Q-6 of this section. 

Deleted: argon-oxygen 
210

CO * (Steel) *[(CSteelin ) (CSteelout) ] ( ) R * (CR)

12

44

2 = − − (Eq. Q-6) 

Where: 

CO2 = Annual CO2 mass emissions from the 

decarburization vessel (metric tons). 

44/12 = Ratio of molecular weights, CO2 to carbon. 

(Steel) = Annual mass of molten steel charged to the 

vessel (metric tons). 

(CSteelin) = Carbon content of the molten steel before 

decarburization, from the carbon analysis 

results (percent by weight, expressed as a 

decimal fraction). 

(CSteelout) = Carbon content of the molten steel after 

decarburization, from the carbon analysis 

results (percent by weight, expressed as a 

decimal fraction). 

(R) = Annual mass of air pollution control residue 

collected (metric tons). 

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results 

(percent by weight, expressed as a decimal 

fraction). 

(vii) For direct reduction furnaces, estimate CO2 

emissions using Equation Q-7 of this section. 

( ) ( ) ( ) ( )

( ) ( ) ( ) ( )

( ) ( ) ( ) *( ) ( )* ( )]

* *

*[ * * *0.001 *

12

44

2

Iron NM R

Carbon Other

g gf Ore

Iron C NM C R C

Carbon C Other C

Ore C

MVC

MW CO F C

− − −

+ +

= +

(Eq. Q-7) 

Where: 

CO2 = Annual CO2 mass emissions from the direct 

reduction furnace (metric tons). 

44/12 = Ratio of molecular weights, CO2 to carbon. 

(Fg) = Annual volume of the gaseous fuel combusted 

(scf). 

Deleted: argon-oxygen 
211

(Cgf) = Carbon content of the gaseous fuel, from the 

fuel analysis results (kg C per kg of fuel). 

MW = Molecular weight of the gaseous fuel (kg/kgmole). 

MVC = Molar volume conversion factor (849.5 scf per 

kg-mole at standard conditions). 

0.001 = Conversion factor from kg to metric tons. 

(Ore) = Annual mass of iron ore or iron ore pellets 

fed to the furnace (metric tons). 

(COre) = Carbon content of the iron ore or iron ore 

pellets, from the carbon analysis results 

(percent by weight, expressed as a decimal 

fraction). 

(Carbon) = Annual mass of carbonaceous materials (e.g., 

coal, coke) charged to the furnace (metric 

tons). 

(CCarbon) = Carbon content of the carbonaceous materials, 

from the carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(Other) = Annual mass of other materials charged to the 

furnace (metric tons). 

(COther) = Average carbon content of the other materials 

charged to the furnace, from the carbon 

analysis results (percent by weight, expressed 

as a decimal fraction). 

(Iron) = Annual mass of iron produced (metric tons). 

(CIron) = Carbon content of the iron, from the carbon 

analysis results (percent by weight, expressed 

as a decimal fraction). 

(NM) = Annual mass of non-metallic materials produced 

by the furnace (metric tons). 

(CNM) = Carbon content of the non-metallic materials, 

from the carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(R) = Annual mass of air pollution control residue 

collected (metric tons). 

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results 
212

(percent by weight, expressed as a decimal 

fraction). 

(2) Site-specific emission factor method. Conduct a 

performance test and measure CO2 emissions from all exhaust 

stacks for the process and measure either the feed rate of 

materials into the process or the production rate during 

the test as described in paragraphs (b)(2)(i) through 

(b)(2)(iv) of this section. 

(i) You must measure the process production rate or 

process feed rate, as applicable, during the performance 

test according to the procedures in §98.174(c)(5) and 

calculate the average rate for the test period in metric 

tons per hour. 

(ii) You must calculate the hourly CO2 emission rate 

using Equation Q-8 of this section and determine the 

average hourly CO2 emission rate for the test. 











 −

=

−

100

100 %

5.18 10 * * *

2

2

7

2

H O

CO x CCO Q (Eq. Q-8) 

Where: 

CO2 = CO2 mass emission rate, corrected for moisture 

(metric tons/hr). 

5.18 x 10-7 = Conversion factor (metric tons/scf-% CO2). 

CCO2 = Hourly CO2 concentration, dry basis (% CO2). 

Q = Hourly stack gas volumetric flow rate (scfh). 

%H2O = Hourly moisture percentage in the stack gas. 

(iii) You must calculate a site-specific emission 

factor for the process in metric tons of CO2 per metric ton 
213

of feed or production, as applicable, by dividing the 

average hourly CO2 emission rate during the test by the 

average hourly feed or production rate during the test. 

(iv) You must calculate CO2 emissions for the process 

by multiplying the emission factor by the total amount of 

feed or production, as applicable, for the reporting 

period. 

(c) You must determine emissions of CO2 from the coke 

pushing process in mtCO2e by multiplying the metric tons of 

coal charged to the coke ovens during the reporting period 

by 0.008. 

(d) If GHG emissions from a taconite indurating 

furnace, basic oxygen furnace, non-recovery coke oven 

battery, sinter process, EAF, decarburization vessel, or 

direct reduction furnace are vented through the same stack 

as any combustion unit or process equipment that reports CO2

emissions using a CEMS that complies with the Tier 4 

Calculation Methodology in subpart C of this part (General 

Stationary Fuel Combustion Sources), then the calculation 

methodology in paragraph (b) of this section shall not be 

used to calculate process emissions. The owner or operator 

shall report under this subpart the combined stack 

emissions according to the Tier 4 Calculation Methodology 

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

Deleted: argon-oxygen 
214

in subpart C of this part (General Stationary Fuel 

Combustion Sources). 

§98.174 Monitoring and QA/QC requirements.

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

CO2 emissions consistent with subpart C of this part, you 

must meet the monitoring and QA/QC requirements of 

§98.34(c). 

(b) If you determine CO2 emissions using the carbon 

mass balance procedure in §98.173(b)(1), you must: 

(1) Except as provided in paragraph (b)(4) of this 

section, determine the mass of each process input and 

output other than fuels using the same plant instruments or 

procedures that are used for accounting purposes (such as 

weigh hoppers, belt weigh feeders, weighed purchased 

quantities in shipments or containers, combination of bulk 

density and volume measurements, etc.), record the totals 

for each process input and output for each calendar month, 

and sum the monthly mass to determine the annual mass for 

each process input and output. Determine the mass rate of 

fuels using the procedures for combustion units in §98.34. 

(2) Except as provided in paragraph (b)(4) of this 

section, determine the carbon content of each process input 

and output annually for use in the applicable equations in 

§98.173(b)(1) based on analyses provided by the supplier or 
215

by the average carbon content determined by collecting and 

analyzing at least three samples each year using the 

standard methods specified in paragraphs (b)(2)(i) through 

(b)(2)(vi) of this section as applicable. 

(i) ASTM C25-06, Standard Test Methods for Chemical 

Analysis of Limestone, Quicklime, and Hydrated Lime

(incorporated by reference, see §98.7) for limestone, 

dolomite, and slag. 

(ii) ASTM D5373-08 Standard Test Methods for 

Instrumental Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal (incorporated by 

reference, see §98.7) for coal, coke, and other 

carbonaceous materials. 

(iii) ASTM E1915-07a, Standard Test Methods for 

Analysis of Metal Bearing Ores and Related Materials by 

Combustion Infrared-Absorption Spectrometry (incorporated 

by reference, see §98.7) for iron ore, taconite pellets, 

and other iron-bearing materials. 

(iv) ASTM E1019-08, Standard Test Methods for 

Determination of Carbon, Sulfur, Nitrogen, and Oxygen in 

Steel, Iron, Nickel, and Cobalt Alloys by Various 

Combustion and Fusion Techniques (incorporated by 

reference, see §98.7) for iron and ferrous scrap. 
216

(v) ASM CS-104 UNS No. G10460 - Alloy Digest April 

1985 (Carbon Steel of Medium Carbon Content) (incorporated 

by reference, see §98.7); ISO/TR 15349-1:1998, Unalloyed 

steel—Determination of low carbon content, Part 1: Infrared 

absorption method after combustion in an electric 

resistance furnace (by peak separation) (1998-10-15) First 

Edition (incorporated by reference, see §98.7); or ISO/TR 

15349-3:1998, Unalloyed steel-Determination of low carbon 

content Part 3: Infrared absorption method after combustion 

in an electric resistance furnace (with preheating) (1998-

10-15) First Edition (incorporated by reference, see §98.7) 

as applicable for steel. 

(vi) For each process input that is a fuel, determine 

the carbon content and molecular weight (if applicable) 

using the applicable methods listed in §98.34. 

(3) For solid ferrous materials charged to basic 

oxygen process furnaces or EAFs that differ in carbon 

content, you may determine a weighted average carbon 

content based on the carbon content of each type of ferrous 

material and the average weight percent of each type that 

is used. Examples of these different ferrous materials 

include carbon steel, low carbon steel, stainless steel, 

high alloy steel, pig iron, iron scrap, and direct reduced 

iron. 
217

(4) If you document that a specific process input or 

output contributes less than one percent of the total mass 

of carbon into or out of the process, you do not have to 

determine the monthly mass or annual carbon content of that 

input or output. 

(5) Except as provided in paragraph (b)(4) of this 

section, you must determine the annual carbon content and 

monthly mass rate of any input or output that contains 

carbon that is not listed in the equations in §98.173(b)(1) 

using the procedures in paragraphs (b)(1) and (b)(2) of 

this section. 

(c) If you determine CO2 emissions using the sitespecific emission factor procedure in §98.173(b)(2), you 

must: 

(1) Conduct an annual performance test that is based 

on representative performance (i.e., performance based on 

normal operating conditions) of the affected process. 

(2) For the furnace exhaust from basic oxygen 

furnaces, EAFs, decarburization vessels, and direct 

reduction furnaces, sample the furnace exhaust for at least 

three complete production cycles that start when the 

furnace is being charged and end after steel or iron and 

slag have been tapped. For EAFs that produce both carbon 

steel and stainless or specialty (low carbon) steel, 

Deleted: argon-oxygen 
218

develop an emission factor for the production of both types 

of steel. 

(3) For taconite indurating furnaces, non-recovery 

coke batteries, and sinter processes, sample for at least 3 

hours. 

(4) Conduct the stack test using EPA Method 3A at 40 

CFR part 60, appendix A-2 to measure the CO2 concentration, 

Method 2, 2A, 2C, 2D, or 2F at 40 CFR part 60, appendix A-1 

or Method 26 at 40 CFR part 60, appendix A-2 to determine 

the stack gas volumetric flow rate, and Method 4 at 40 CFR 

part 60, at appendix A-3 to determine the moisture content 

of the stack gas. 

(5) Determine the mass rate of process feed or 

process production (as applicable) during the test using 

the same plant instruments or procedures that are used for 

accounting purposes (such as weigh hoppers, belt weigh 

feeders, combination of bulk density and volume 

measurements, etc.) 

(6) If your process operates under different 

conditions as part of normal operations in such a manner 

that CO2 emissions change by more than 20 percent (e.g., 

routine changes in the carbon content of the sinter feed or 

change in grade of product), you must perform emission 

testing and develop separate emission factors for these 
219

different operating conditions and determine emissions 

based on the number of hours the process operates and the 

production or feed rate (as applicable) at each specific 

different condition. 

(7) If your EAF and decarburization vessel exhaust to 

a common emission control device and stack, you must sample 

each process in the ducts before the emissions are 

combined, sample each process when only one process is 

operating, or sample the combined emissions when both 

processes are operating and base the site-specific emission 

factor on the steel production rate of the EAF. 

(8) The results of a performance test must include 

the analysis of samples, determination of emissions, and 

raw data. The performance test report must contain all 

information and data used to derive the emission factor. 

(d) For a coke pushing process, determine the metric 

tons of coal charged to the coke ovens and record the 

totals for each pushing process for each calendar month. 

Coal charged to coke ovens can be measured using weigh 

belts or a combination of measuring volume and bulk 

density. 

§98.175 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations in §98.173 is required. 

Deleted: argon-oxygen 
220

Therefore, whenever a quality-assured value of a required 

parameter is unavailable, a substitute data value for the 

missing parameter shall be used in the calculations as 

specified in the paragraphs (a) and (b) of this section. 

You must follow the missing data procedures in §98.255(b) 

of subpart Y (Petroleum Refineries) of this part for flares 

burning coke oven gas or blast furnace gas. You must 

document and keep records of the procedures used for all 

such estimates. 

(a) For each missing data for the carbon content of 

inputs and outputs for facilities that estimate emissions 

using the carbon mass balance procedure in §98.173(b)(1) or 

for facilities that estimate emissions using the sitespecific emission factor procedure in §98.173(b)(2); 100 

percent data availability is required. You must repeat the 

test for average carbon contents of inputs and outputs 

according to the procedures in §98.174(b)(2). Similarly, 

you must repeat the test to determine the site-specific 

emission factor if data on the CO2 emission rate, process 

production rate or process feed rate are missing. 

(b) For missing records of the monthly mass or volume 

of carbon-containing inputs and outputs using the carbon 

mass balance procedure in §98.173(b)(1), the substitute 

data value must be based on the best available estimate of 
221

the mass of the input or output material from all available 

process data or data used for accounting purposes. 

§98.176 Data reporting requirements.

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

each annual report must contain the information required in 

paragraphs (a) through (h) of this section for each coke 

pushing operation; taconite indurating furnace; basic 

oxygen furnace; non-recovery coke oven battery; sinter 

process; EAF; decarburization vessel; direct reduction 

furnace; and flare burning coke oven gas or blast furnace 

gas: 

(a) Unit identificatin number and annual CO2 emissions 

(in metric tons. 

(b) Annual production quantity (in metric tons) for 

taconite pellets, coke, sinter, iron, and raw steel. 

(c) If a CEMS is used to measure CO2 emissions, then 

you must report the relevant information required under 

§98.36 for the Tier 4 Calculation Methodology. 

(d) If a CEMS is not used to measure CO2 emissions, 

then you must report for each process whether the emissions 

were determined using the carbon mass balance method in 

§98.173(b)(1) or the site-specific emission factor method 

in §98.173(b)(2). 

Deleted: f

Deleted: argon-oxygen 

Deleted: and

Deleted: 7
222

(e) If you use the carbon mass balance method in 

§98.173(b)(1) to determine CO2 emissions, you must report 

the following information for each process: 

(1) The carbon content of each process input and 

output used to determine CO2 emissions. 

(2) Whether the carbon content was determined from 

information from the supplier or by laboratory analysis, 

and if by laboratory analysis, the method used. 

(3) The annual volume of each type of gaseous fuel 

(reported separately for each type in standard cubic feet), 

the annual volume of each type of liquid fuel (reported 

separately for each type in gallons), and the annual mass 

(in metric tons) of each other process inputs and outputs 

used to determine CO2 emissions. 

(4) The molecular weight of gaseous fuels. 

(5) If you used the missing data procedures in 

§98.175(b), you must report how the monthly mass for each 

process input or output with missing data was determined 

and the number of months the missing data procedures were 

used. 

(f) If you used the site-specific emission factor 

method in §98.173(b)(2) to determine CO2 emissions, you must 

report the following information for each process: 

Deleted: all
223

(1) The measured average hourly CO2 emission rate 

during the test(in metric tons per hour). 

(2) The average hourly feed or production rate (as 

applicable) during the test (in metric tons per hour). 

(3) The site-specific emission factor (in metric tons 

of CO2 per metric ton of feed or production, as applicable). 

(4) The annual feed or production rate (as 

applicable) used to estimate annual CO2 emissions (in metric 

tons).

(g) The annual amount of coal charged to the coke 

ovens (in metric tons).

(h) For flares burning coke oven gas or blast furnace 

gas, the information specified in §98.256(e) of subpart Y 

(Petroleum Refineries) of this part.

§98.177 Records that must be retained.

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

must retain the records specified in paragraphs (a) through 

(e) of this section, as applicable. Facilities that use 

CEMS to measure emissions must also retain records of the 

verification data required for the Tier 4 Calculatin 

Methodology in §98.36(e). 

(a) Records of all analyses and calculations 

conducted, including all information reported as required 

under §98.176. 
224

(b) When the carbon mass balance method is used to 

estimate emissions for a process, the monthly mass of each 

process input and output that are used to determine the 

annual mass. 

(c) Production capacity (in metric tons per year) for 

the production of taconite pellets, coke, sinter, iron, and 

raw steel. 

(d) Annual operating hours for each taconite 

indurating furnace, basic oxygen furnace, non-recovery coke 

oven battery, sinter process, electric arc furnace, 

decarburization vessel, and direct reduction furnace. 

(e) Facilities must keep records that include a 

detailed explanation of how company records or measurements 

are used to determine all sources of carbon input and 

output and the metric tons of coal charged to the coke 

ovens (e.g., weigh belts, a combination of measuring volume 

and bulk density). You also must document the procedures 

used to ensure the accuracy of the measurements of fuel 

usage including, but not limited to, calibration of 

weighing equipment, fuel flow meters, coal usage including, 

but not limited to, calibration of weighing equipment and 

other measurement devices. The estimated accuracy of 

measurements made with these devices must also be recorded, 

Deleted: s

Deleted: ies

Deleted: duction, blast 

furnaces, direct reduced 

iron furnaces, and

Deleted: s
225

and the technical basis for these estimates must be 

provided. 

§98.178 Definitions.

All terms used in this subpart have the same meaning 

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

Subpart S—Lime Manufacturing 

§98.190 Definition of the source category.

(a) Lime manufacturing plants (LMPs) engage in the 

manufacture of a lime product (e.g., calcium oxide, highcalcium quicklime, calcium hydroxide, hydrated lime, 

dolomitic quicklime, dolomitic hydrate, or other lime 

products) by calcination of limestone, dolomite, shells or 

other calcareous substances as defined in 40 CFR 

63.7081(a)(1). 

(b) This source category includes all LMPs unless the 

LMP is located at a kraft pulp mill, soda pulp mill, 

sulfite pulp mill, or only processes sludge containing 

calcium carbonate from water softening processes. The lime 

manufacturing source category consists of marketed and nonmarketed lime manufacturing facilities. 

(c) Lime kilns at pulp and paper manufacturing 

facilities must report emissions under subpart AA of this 

part (Pulp and Paper Manufacturing). 

§98.191 Reporting threshold.
226

You must report GHG emissions under this subpart if 

your facility is a lime manufacturing plant as defined in 

§98.190 and the facility meets the requirements of either 

§98.2(a)(1) or (a)(2). 

§98.192 GHGs to report.

You must report: 

(a) CO2 process emissions from lime kilns. 

(b) CO2 emissions from fuel combustion at lime kilns. 

(c) N2O and CH4 emissions from fuel combustion at each 

lime kiln. You must report these emissions under 40 CFR 

part 98, subpart C (General Stationary Fuel Combustion 

Sources). 

(d) CO2, N2O, and CH4 emissions from each stationary 

fuel combustion unit other than lime kilns. You must 

report these emissions under 40 CFR part 98, subpart C 

(General Stationary Fuel Combustion Sources). 

(e) CO2 collected and transferred off site under 40 

CFR part 98, following the requirements of subpart PP of 

this part (Suppliers of Carbon Dioxide (CO2)). 

§98.193 Calculating GHG emissions. 

You must calculate and report the annual process CO2

emissions from all lime kilns combined using the procedure 

in paragraphs (a) and (b) of this section. 
227

(a) If all lime kilns meet the conditions specified 

in §98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and 

report under this subpart the combined process and 

combustion CO2 emissions by operating and maintaining a CEMS 

to measure CO2 emissions according to the Tier 4 Calculation 

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

requirements for Tier 4 in subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(b) If CEMS are not required to be used to determine 

CO2 emissions from all lime kilns under paragraph (a) of 

this section, then you must calculate and report the 

process and combustion CO2 emissions from the lime kilns by 

using the procedures in either paragraph (b)(1) or (b)(2) 

of this section. 

(1) Calculate and report under this subpart the 

combined process and combustion CO2 emissions by operating 

and maintaining a CEMS to measure CO2 emissions from all 

lime kilns according to the Tier 4 Calculation Methodology 

specified in §98.33(a)(4) and all associated requirements 

for Tier 4 in subpart C of this part (General Stationary 

Fuel Combustion Sources). 

(2) Calculate and report process and combustion CO2

emissions separately using the procedures specified in 

paragraphs (b)(2)(i) through (b)(2)(v) of this section. 
228

(i) You must calculate a monthly emission factor for 

each type of lime produced using Equation S-1 of this 

section. Calcium oxide and magnesium oxide content must be 

analyzed monthly for each lime product type that is 

produced: 

[ ]

2205

2000 ( ) ( ) * LIME,i,n CaO i,n MgO M i,n EF = SR ∗CaO + SR ∗ gO (Eq. S-1) 

Where: 

EFLIME,i,n = Emission factor for lime type i, for month n 

(metric tons CO2/ton lime). 

SRCaO = Stoichiometric ratio of CO2 and CaO for 

calcium carbonate [see Table S-1 of this 

subpart] (metric tons CO2/metric tons CaO). 

SRMgO = Stoichiometric ratio of CO2 and MgO for 

magnesium carbonate (See Table S-1 of this 

subpart) (metric tons CO2/metric tons MgO). 

CaOi,n = Calcium oxide content for lime type i, for 

month n, determined according to §98.194(c) 

(metric tons CaO/metric ton lime). 

MgOi,n = Magnesium oxide content for lime type i, for 

month n, determined according to §98.194(c) 

(metric tons MgO/metric ton lime). 

2000/2205 = Conversion factor for tons to metric tons. 

(ii) You must calculate a monthly emission factor for 

each type of calcined byproduct/waste sold (including lime 

kiln dust) using Equation S-2 of this section: 

[ ]

2205

2000 ( ) ( ) * LKD ,i,n CaO LKD ,i,n MgO M LKD ,i,n EF = SR ∗CaO + SR ∗ gO (Eq. S-2) 

Where: 

EFLKD,i,n = Emission factor for calcined lime 

byproduct/waste type i sold, for month n 

(metric tons CO2/ton lime byproduct). 

Deleted: metric 

Deleted: sold 
229

SRCaO = Stoichiometric ratio of CO2 and CaO for 

calcium carbonate (see Table S-1 of this 

subpart( (metric tons CO2/metric tons CaO). 

SRMgO = Stoichiometric ratio of CO2 and MgO for 

magnesium carbonate (See Table S-1 of this 

subpart) (metric tons CO2/metric tons MgO). 

CaOLKD,i,n = Calcium oxide content for calcined lime 

byproduct/waste type i sold, for month n 

(metric tons CaO/metric ton lime). 

MgOLKD,i,n = Magnesium oxide content for calcined lime 

byproduct/waste type i sold, for month n 

(metric tons MgO/metric ton lime). 

2000/2205 = Conversion factor for tons to metric tons. 

(iii) You must calculate the annual CO2 emissions from 

each type of calcined byproduct/waste that is not sold 

(including lime kiln dust and scrubber sludge) using 

Equation S-3 of this section: 

[ ]

2205

2000 Ewaste ,i = ∑ (SRCaO ∗CaOwaste ,i

) + (SRMgO ∗ MgOwaste ,i) * M waste ,i * (Eq. S-3) 

Where: 

Ewaste,i = Annual CO2 emissions for calcined lime 

byproduct/waste type i that is not sold

(metric tons CO2). 

SRCaO = Stoichiometric ratio of CO2 and CaO for 

calcium carbonate (see Table S-1 of this 

subpart) (metric tons CO2/metric tons CaO). 

SRMgO = Stoichiometric ratio of CO2 and MgO for 

magnesium carbonate (See Table S-1 of this 

subpart) (metric tons CO2/metric tons MgO). 

CaOwaste,i = Calcium oxide content for calcined lime 

byproduct/waste type i that is not sold 

(metric tons CaO/metric ton lime). 

MgOwaste,i = Magnesium oxide content for calcined lime 

byproduct/waste type i that is not sold 

(metric tons MgO/metric ton lime). 

Deleted: sold 

Deleted: sold 

Deleted: 

Deleted: metric 

Deleted: unsold 

Deleted: unsold 

Deleted: unsold 
230

Mwaste,i = Annual weight or mass of calcined

byproducts/wastes for lime type i that is not 

sold (tons). 

2000/2205 = Conversion factor for tons to metric tons. 

(iv) You must calculate annual CO2 process emissions 

for all kilns using Equation S-4 of this section: 

∑∑ ∑∑ ∑ = = = = =

= ∗ + ∗ +

z

i

waste i

t

i

b

i n

LIME i n LKD i n LKD i n

n

ECO EFLIME i n M EF M E

1

,

1 1

12

1

, , , , , ,

12

1

, ,

( ) )

2

(Eq. S-4) 

Where: 

ECO2 = Annual CO2 process emissions from lime 

production from all kilns (metric tons/year). 

EFLIME,i,n = Emission factor for lime type i produced, in 

calendar month n (metric tons CO2/ton lime) 

from Equation S-1 of this section. 

MLIME,i,n = Weight or mass of lime type i produced in 

calendar month n (tons). 

EFLKD,i,n = Emission factor of calcined byproducts/wastes 

sold for lime type i in calendar month n, 

(metric tons CO2/ton byproduct/waste) from 

Equation S-2 of this section. 

MLKD,i,n = Monthly weight or mass of calcined 

byproducts/waste sold (such as lime kiln dust, 

LKD) for lime type i in calendar month n 

(tons). 

Ewaste,i = Annual CO2 emissions for calcined lime 

byproduct/waste type i that is not sold

(metric tons CO2) from Equation S-3 of this 

section. 

t = Number of lime types produced 

b = Number of calcined byproducts/wastes that are 

sold 

z = Number of calcined byproducts/wastes that are 

not sold 

Deleted: unsold 

Deleted: metric 

Deleted: unsold 
231

(v) Calculate and report under subpart C of this part 

(General Stationary Fuel Combustion Sources) the combustion 

CO2 emissions from each lime kiln according to the 

applicable requirements in subpart C. 

§98.194 Monitoring and QA/QC requirements.

(a) You must determine the total quantity of each 

type of lime product that is produced and each calcined 

byproduct/waste (such as lime kiln dust) that is sold. The 

quantities of each should be directly measured monthly with 

the same plant instruments used for accounting purposes, 

including but not limited to, calibrated weigh feeders, 

rail or truck scales, and barge measurements. The direct 

measurements of each lime product shall be reconciled 

annually with the difference in the beginning of and end of 

year inventories for these products, when measurements 

represent lime sold. 

(b) You must determine the annual quantity of each 

calcined byproduct/waste generated that is not sold by 

either direct measurement using the same instruments 

identified in paragraph (a) of this section or by using a 

calcined byproduct/waste generation rate. 

(c) You must determine the chemical composition 

(percent total CaO and percent total MgO) of each type of 

lime product that is produced and each type of calcined 

Deleted: type of lime 
232

byproduct/waste sold according to paragraph (c)(1) or 

(c)(2) of this section. You must determine the chemical 

composition of each type of lime product that is produced 

and each type of calcined byproduct/waste sold on a monthly 

basis. You must determine the chemical composition for 

each type of calcined byproduct/waste that is not sold on 

an annual basis. 

(1) ASTM C25-06 Standard Test Methods for Chemical 

Analysis of Limestone, Quicklime, and Hydrated Lime 

(incorporated by reference-see §98.7). 

(2) The National Lime Association’s CO2 Emissions 

Calculation Protocol for the Lime Industry English Units 

Version, February 5, 2008 Revision-National Lime 

Association (incorporated by reference see §98.7). 

(d) You must use the analysis of calcium oxide and 

magnesium oxide content of each lime product that is

produced and that is collected during the same month as the 

production data in monthly calculations. 

(e) You must follow the quality assurance/quality 

control procedures (including documentation) in National 

Lime Association’s CO2 Emissions Calculation Protocol for 

the Lime Industry-English Units Version, February 5, 2008 

Revision-National Lime Association (incorporated by 

reference see §98.7). 
233

§98.195 Procedures for estimating missing data.

For the procedure in §98.193(b)(1), a complete record 

of all measured parameters used in the GHG emissions 

calculations is required (e.g., oxide content, quantity of 

lime products, etc.). Therefore, whenever a qualityassured value of a required parameter is unavailable, a 

substitute data value for the missing parameter shall be 

used in the calculations as specified in paragraphs (a) or 

(b) of this section. You must document and keep records of 

the procedures used for all such estimates. 

(a) For each missing value of the quantity of lime 

produced (by lime type), and quantity of calcined

byproduct/waste produced and sold, the substitute data 

value shall be the best available estimate based on all 

available process data or data used for accounting 

purposes. 

(b) For missing values related to the CaO and MgO 

content, you must conduct a new composition test according 

to the standard methods in §98.194 (c)(1) or (c)(2). 

§98.196 Data reporting requirements.

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

each annual report must contain the information specified 

in paragraphs (a) or (b) of this section, as applicable. 

Deleted: 2
234

(a) If a CEMS is used to measure CO2 emissions, then 

you must report under this subpart the relevant information 

required by §98.36 and the information listed in paragraphs 

(a)(1) through (a)(8) of this section. 

(1) Method used to determine the quantity of lime

that is produced and sold. 

(2) Method used to determine the quantity of calcined 

lime byproduct/waste sold. 

(3) Beginning and end of year inventories for each 

lime product that is produced, by type. 

(4) Beginning and end of year inventories for 

calcined lime byproducts/wastes sold, by type. 

(5) Annual amount of calcined lime byproduct/waste 

sold, by type (tons). 

(6) Annual amount of lime product sold, by type 

(tons). 

(7) Annual amount of calcined lime byproduct/waste 

that is not sold, by type (tons). 

(8) Annual amount of lime product not sold, by type 

(tons). 

(b) If a CEMS is not used to measure CO2 emissions, 

then you must report the information listed in paragraphs 

(b)(1) through (b)(17) of this section. 
235

(1) Annual CO2 process emissions from all kilns 

combined (metric tons). 

(2) Monthly emission factors for each lime type

produced. 

(3) Monthly emission factors for each calcined 

byproduct/waste by lime type that is sold. 

(4) Standard method used (ASTM or NLA testing method) 

to determine chemical compositions of each lime type 

produced and each calcined lime byproduct/waste type. 

(5) Monthly results of chemical composition analysis 

of each type of lime product produced and calcined 

byproduct/waste sold. 

(6) Annual results of chemical composition analysis 

of each type of lime byproduct/waste that is not sold. 

(7) Method used to determine the quantity of lime 

produced and/or lime sold. 

(8) Monthly amount of lime product sold, by type 

(tons). 

(9) Method used to determine the quantity of calcined 

lime byproduct/waste sold. 

(10) Monthly amount of calcined lime byproduct/waste 

sold, by type (tons). 

(11) Annual amount of calcined lime byproduct/waste 

that is not sold, by type (tons). 

Deleted: sold 
236

(12) Monthly weight or mass of each lime type 

produced (tons). 

(13) Beginning and end of year inventories for each 

lime product that is produced. 

(14) Beginning and end of year inventories for 

calcined lime byproducts/wastes sold. 

(15) Annual lime production capacity (tons) per 

facility. 

(16) Number of times in the reporting year that 

missing data procedures were followed to measure lime 

production (months) or the chemical composition of lime 

products sold (months). 

(17) Indicate whether CO2 was used on-site (i.e. for 

use in a purification process). If CO2 was used on-site, 

provide the information in paragraphs (b)(17)(i) and 

(b)(17)(ii) of this section. 

(i) The annual amount of CO2 captured for use in the 

on-site process. 

(ii) The method used to determine the amount of CO2

captured. 

§98.197 Records that must be retained.

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

must retain the records specified in paragraphs (a) and (b) 

of this section. 
237

(a) Annual operating hours in calendar year. 

(b) Records of all analyses (e.g. chemical 

composition of lime products, by type) and calculations 

conducted. 

§98.198 Definitions. 

All terms used in this subpart have the same meaning 

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

Table S-1 of Subpart S—Basic Parameters for the Calculation 

of Emission Factors for Lime Production 

Variable Stoichiometric ratio 

SRCaO 0.7848 

SRMgO 1.0918 

Subpart V—Nitric Acid Production 

§98.220 Definition of Source Category.

A nitric acid production facility uses one or more 

trains to produce weak nitric acid (30 to 70 percent in 

strength). A nitric acid train produces weak nitric acid 

through the catalytic oxidation of ammonia. 

§98.221 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a nitric acid train and the facility 

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

§98.222 GHGs to report.

(a) You must report N2O process emissions from each 

nitric acid production train as required by this subpart. 
238

(b) You must report under subpart C of this part 

(General Stationary Fuel Combustion Sources) the emissions 

of CO2, CH4, and N2O from each stationary combustion unit by 

following the requirements of subpart C. 

§98.223 Calculating GHG emissions. 

(a) You must determine annual N2O process emissions 

from each nitric acid train according to paragraphs (a)(1) 

or (a)(2) of this section. 

(1) Use a site-specific emission factor and 

production data according to paragraphs (b) through (i) of 

this section. 

(2) Request Administrator approval for an alternative 

method of determining N2O emissions according to paragraphs 

(a)(2)(i) and (a)(2)(ii) of this section. 

(i) You must submit the request within 45 days 

following promulgation of this subpart or within the first 

30 days of each subsequent reporting year. 

(ii) If the Administrator does not approve your 

requested alternative method within 150 days of the end of 

the reporting year, you must determine the N2O emissions for 

the current reporting period using the procedures specified 

in paragraph (a)(1) of this section. 

Deleted: h

Deleted: factor 
239

(b) You must conduct an annual performance test for 

each nitric acid train according to paragraphs (b)(1) 

through (b)(3) of this section. 

(1) You must conduct the performance test at the 

absorber tail gas vent, referred to as the test point, for 

each nitric acid train according to §98.224(b) through (f). 

(2) You must conduct the performance test under 

normal process operating conditions. 

(3) You must measure the production rate during the 

performance test and calculate the production rate for the 

test period in metric tons (100 percent acid basis) per 

hour. 

(c) Using the results of the performance test in 

paragraph (b) of this section, you must calculate an 

average site-specific emission factor for each nitric acid 

train “t” according to Equation V-1 of this section: 

n

P

C Q

EF

n

N O

N Ot

∑

∗ × ∗

=

−

1

7

2

2

1.14 10

(Eq. V-1) 

Where: 

EFN2Ot = Average site-specific N2O emissions factor for 

nitric acid train “t” (lb N2O generated/ton 

nitric acid produced, 100 percent acid basis). 

CN2O = N2O concentration for each test run during the 

performance test (ppm N2O). 

1.14x10-7= Conversion factor (lb/dscf-ppm N2O). 

Q = Volumetric flow rate of effluent gas for each 

test run during the performance test (dscf/hr). 

Deleted: measure N2O 

emissions from

Deleted: using the methods 

specified in

Deleted: d

Deleted: and without using 

N2O abatement technology (if 

applicable)

Deleted: You must determine 

an N2O emissions factor to 

use in Equation V-3 of this 

section according to 

paragraphs (c)(1) or (c)(2) 

of this section. ¶

(1) You may request 

Administrator approval for 

an alternative method of 

determining N2O 

concentration according to 

the procedures in paragraphs 

(a)(2)(i) and (a)(2)(ii) of 

this section. Alternative 

methods include the use of 

N2O CEMs. ¶

(2) 
240

P = Production rate for each test run during the 

performance test (tons nitric acid produced per 

hour, 100 percent acid basis). 

n = Number of test runs. 

(d) If nitric acid train “t” exhausts to any N2O 

abatement technology “N” after the test point, you must 

determine the destruction efficiency for each N2O abatement 

technology “N” according to paragraphs (d)(1), (d)(2), or 

(d)(3) of this section. 

(1) Use the manufacturer’s specified destruction 

efficiency. 

(2) Estimate the destruction efficiency through 

process knowledge. Examples of information that could 

constitute process knowledge include calculations based on 

material balances, process stoichiometry, or previous test 

results provided the results are still relevant to the 

current vent stream conditions. You must document how 

process knowledge (if applicable) was used to determine the 

destruction efficiency. 

(3) Calculate the destruction efficiency by 

conducting an additional performance test on the emissions 

stream following the N2O abatement technology. 

(e) If nitric acid train “t” exhausts to any N2O 

abatement technology “N” after the test point, you must 

determine the annual amount of nitric acid produced on 

Deleted: applicable

Deleted: applicable
241

train “t” while N2O abatement technology “N” is operating 

according to §98.224(f). Then you must calculate the 

abatement utilization factor for each N2O abatement 

technology “N” for each nitric acid train “t” according to 

Equation V-2 of this section. 

a t

a t N

t N

P

P

AF

,

, ,

, = (Eq. V-2) 

Where: 

AFt,N = Abatement utilization factor of N2O abatement 

technology “N” at nitric acid train “t” 

(fraction of annual production that 

abatement technology is operating). 

Pa t = Total annual nitric acid production from 

nitric acid train “t” (ton acid produced, 

100 percent acid basis). 

Pa,t,N = Annual nitric acid production from nitric 

acid train “t” during which N2O abatement 

technology “N” was operational (ton acid 

produced, 100 percent acid basis). 

(f) [Reserved]

(g) You must calculate N2O emissions for each nitric 

acid train “t” according to paragraph (g)(1) or (g)(2) of 

this section.

(1) If nitric acid train “t” exhausts to any N2O 

abatement technology “N” after the test point, you must use

the emissions factor (determined in Equation V-1 of this 

section), the destruction efficiency (determined in 

paragraph (d) of this section), the annual nitric acid 

production (determined in paragraph (i) of this section), 

Deleted: g

Deleted: .

Deleted: The abatement 

factor is calculated

Deleted: N

Deleted: t

Deleted: 

Deleted: Abate 

Deleted: used 

Deleted: You must determine 

the annual amount of nitric 

acid produced and the annual 

amount of nitric acid 

produced while each N2O 

abatement technology is 

operating from each nitric 

acid train (100 percent 

basis).

Deleted: by multiplying

Deleted: by

Deleted: e
242

and the abatement utilization factor (determined in 

paragraph (e) of this section) according to Equation V-3a

of this section: 

∑=

−

=

z

N

N t a t t N t N

N Ot

EF P DF AF

E

1

20 , , ,

2205

* * (1 ( * ))

2

(Eq. V-3a) 

Where: 

EN2Ot = N2O mass emissions per year for nitric acid 

train “t” (metric tons). 

EFN2Ot = Average site-specific N2O emissions factor for 

nitric acid train ”t” (lb N2O generated/ton 

acid produced, 100 percent acid basis). 

Pa t = Annual nitric acid production from the train 

“t” (ton acid produced, 100 percent acid 

basis). 

DFt,N = Destruction efficiency of N2O abatement 

technology N that is used on nitric acid train 

“t” (percent of N2O removed from air stream). 

AFt,N = Abatement utilization factor of N2O abatement 

technology “N” for nitric acid train “t” 

(fraction of annual production that N2O 

abatement technology is operating). 

2204.63 = Conversion factor (lb/metric ton). 

z = Number of N2O abatement technologies on nitric 

acid train “t”. 

(2) If nitric acid train “t” does not exhaust to any 

N2O abatement technology after the test point, you must use 

the emissions factor (determined in Equation V-1 of this 

section), and the annual nitric acid production (determined 

in paragraph (i) of this section) according to Equation V3b of this section: 

2205

20 * ,

2

N t a t

N Ot

EF P

E = (Eq. V-3b)

Deleted: f

Deleted: the annual nitric 

acid production and 

accounting for N2O 

abatement, 

Deleted: N 

Deleted: N

Deleted: different 

Deleted: e
243

Where:

EN2Ot = N2O mass emissions per year for nitric acid train 

“t” (metric tons).

EFN2Ot = Average site-specific N2O emissions factor for 

nitric acid train ”t” (lb N2O generated/ton acid 

produced, 100 percent acid basis).

Pa, t = Annual nitric acid production from nitric acid 

train “t” (ton acid produced, 100 percent acid 

basis).

2205 = Conversion factor (lb/metric ton).

(h) You must determine the annual nitric acid 

production emissions combined from all nitric acid trains 

at your facility using Equation V-4 of this section: 

∑=

=

m

t

N O EN Ot

1

2 2 (Eq. V-4) 

Where: 

N2O = Annual process N2O emissions from nitric acid 

production facility (metric tons) 

EN2Ot = N2O mass emissions per year for nitric acid train 

“t” (metric tons). 

m = Number of nitric acid trains. 

(i) You must determine the total annual amount of 

nitric acid produced on nitric acid train “t” for each 

nitric acid train (tons acid produced, 100 percent acid 

basis), according to §98.224(f).

§98.224 Monitoring and QA/QC requirements.

(a) You must conduct a new performance test according 

to a test plan as specified in paragraphs (a)(1) through 

(a)(3) of this section. 

Deleted: g

Deleted: 

Deleted: and calculate a new 

site-specific emissions 

factor 
244

(1) Conduct the performance test annually. The test 

should be conducted at a point during the campaign which is 

representative of the average emissions over the entire 

campaign. Facilities must document the methods used to 

determine the representative point of the campaign when the 

performance test is conducted. 

(2) Conduct the performance test when your nitric 

acid production process is changed, specifically when 

abatement equipment is installed. 

(3) If you requested Administrator approval for an 

alternative method of determining N2O emissions under 

§98.223(a)(2), you must conduct the performance test if 

your request has not been approved by the Administrator 

within 150 days of the end of the reporting year in which 

it was submitted. 

(b) You must measure the N2O concentration during the 

performance test using one of the methods in paragraphs 

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

(1) EPA Method 320 at 40 CFR part 63, appendix A, 

Measurement of Vapor Phase Organic and Inorganic Emissions 

by Extractive Fourier Transform Infrared (FTIR) 

Spectroscopy. 

(2) ASTM D6348-03 Standard Test Method for 

Determination of Gaseous Compounds by Extractive Direct 

Deleted: concentration 
245

Interface Fourier Transform Infrared (FTIR) Spectroscopy 

(incorporated by reference in §98.7). 

(3) An equivalent method, with Administrator 

approval. 

(c) You must determine the production rate(s) (100 

percent basis) from each nitric acid train during the 

performance test according to paragraphs (c)(1) or (c)(2) 

of this section. 

(1) Direct measurement of production and 

concentration (such as using flow meters, weigh scales, for 

production and concentration measurements). 

(2) Existing plant procedures used for accounting 

purposes (i.e. dedicated tank-level and acid concentration 

measurements). 

(d) You must determine the volumetric flow rate 

during the performance test in conjunction with the 

applicable EPA methods in 40 CFR part 60, appendices A-1 

through A-4. Conduct three emissions test runs of 1 hour 

each. All QA/QC procedures specified in the reference test 

methods and any associated performance specifications 

apply. For each test, the facility must prepare an 

emission factor determination report that must include the 

items in paragraphs (d)(1) through (d)(3) of this section. 

Deleted: conduct all 

performance tests
246

(1) Analysis of samples, determination of emissions, 

and raw data. 

(2) All information and data used to derive the 

emissions factor(s). 

(3) The production rate during each test run and how 

it was determined. 

(e) You must determine the total monthly amount of 

nitric acid produced and the monthly amount of nitric acid 

produced while N2O abatement technology (located after the 

test point) is operating from each nitric acid train 

according to the methods in paragraphs (c)(1) or (c)(2) of 

this section. 

(f) You must determine the annual amount of nitric 

acid produced and the annual amount of nitric acid produced

while N2O abatement technology (located after the test 

point) is operating for each train by summing the 

respective monthly nitric acid quantities determined in 

paragraph (e) of this section. 

§98.225 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable, a substitute data value for the missing 

Deleted: tion

Deleted: tion

Deleted: during which

Deleted: tion

Deleted: tion

Deleted: during which

Deleted: production 

Deleted: f
247

parameter shall be used in the calculations as specified in 

paragraphs (a) and (b) of this section. 

(a) For each missing value of nitric acid production, 

the substitute data shall be the best available estimate 

based on all available process data or data used for 

accounting purposes (such as sales records). 

(b) For missing values related to the performance 

test, including emission factors, production rate, and N2O 

concentration, you must conduct a new performance test 

according to the procedures in §98.224 (a) through (d). 

§98.226 Data reporting requirements. 

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

each annual report must contain the information specified 

in paragraphs (a) through (o) of this section. 

(a) Train identification number. 

(b) Annual process N2O emissions from each nitric acid 

train (metric tons). 

(c) Annual nitric acid production from each nitric 

acid train (tons, 100 percent acid basis). 

(d) Annual nitric acid production from each nitric 

acid train during which N2O abatement technology is 

operating (ton acid produced, 100 percent acid basis).

(e) Annual nitric acid production from the nitric 

acid facility (tons, 100 percent acid basis). 

Deleted: for each nitric 

acid production train
248

(f) Number of nitric acid trains. 

(g) Number of different N2O abatement technologies per 

nitric acid train “t”. 

(h) Abatement technologies used (if applicable). 

(i) Abatement technology destruction efficiency for 

each abatement technology (percent destruction). 

(j) Abatement utilization factor for each abatement 

technology (fraction of annual production that abatement 

technology is operating). 

(k) Type of nitric acid process used for each nitric 

acid train (low, medium, high, or dual pressure). 

(l) Number of times in the reporting year that 

missing data procedures were followed to measure nitric 

acid production (months). 

(m) If you conducted a performance test and 

calculated a site-specific emissions factor according to 

§98.223(a)(1), each annual report must also contain the 

information specified in paragraphs (m)(1) through (m)(7) 

of this section. 

(1) Emission factor calculated for each nitric acid 

train (lb N2O/ ton nitric acid, 100 percent acid basis). 

(2) Test method used for performance test. 

Deleted: (if applicable)

Deleted: for each nitric 

acid production facility
249

(3) Production rate per test run during performance 

test (tons nitric acid produced/hr, 100 percent acid 

basis). 

(4) N2O concentration per test run during performance 

test (ppm N2O). 

(5) Volumetric flow rate per test run during 

performance test (dscf/hr). 

(6) Number of test runs during performance test. 

(7) Number of times in the reporting year that a 

performance test had to be repeated (number). 

(n) If you requested Administrator approval for an 

alternative method of determining N2O emissions under 

§98.223(a)(2), each annual report must also contain the 

information specified in paragraphs (n)(1) through (n)(4) 

of this section for each nitric acid production facility. 

(1) Name of alternative method. 

(2) Description of alternative method. 

(3) Request date. 

(4) Approval date. 

(o) Total pounds of synthetic fertilizer produced 

through and total nitrogen contained in that fertilizer.

§98.227 Records that must be retained. 

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

you must retain the records specified in paragraphs (a) 

Deleted: concentration
250

through (g) of this section for each nitric acid production 

facility: 

(a) Records of significant changes to process. 

(b) Documentation of how process knowledge was used 

to estimate abatement technology destruction efficiency (if 

applicable). 

(c) Performance test reports. 

(d) Number of operating hours in the calendar year 

for each nitric acid train (hours). 

(e) Annual nitric acid permitted production capacity 

(tons). 

(f) Measurements, records, and calculations used to 

determine reported parameters. 

(g) Documentation of the procedures used to ensure 

the accuracy of the measurements of all reported 

parameters, including but not limited to, calibration of 

weighing equipment, flow meters, and other measurement 

devices. The estimated accuracy of measurements made with 

these devices must also be recorded, and the technical 

basis for these estimates must be provided. 

§98.228 Definitions.

All terms used in this subpart have the same meaning 

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

Subpart Z—Phosphoric Acid Production 
251

§98.260 Definition of the source category.

The phosphoric acid production source category 

consists of facilities with a wet-process phosphoric acid 

process line used to produce phosphoric acid. A wetprocess phosphoric acid process line is the production unit 

or units identified by an individual identification number 

in an operating permit and/or any process unit or group of 

process units at a facility reacting phosphate rock from a 

common supply source with acid. 

§98.261 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a phosphoric acid production process 

and the facility meets the requirements of either 

§98.2(a)(1) or (a)(2). 

§98.262 GHGs to report.

(a) You must report CO2 process emissions from each 

wet-process phosphoric acid process line. 

(b) You must report under subpart C of this part 

(General Stationary Fuel Combustion Sources) the emissions 

of CO2, CH4, and N2O from each stationary combustion unit 

following the requirements of subpart C of this part. 

§98.263 Calculating GHG emissions.

You must calculate and report the annual process CO2

emissions from each wet-process phosphoric acid process 
252

line using the procedures in either paragraph (a) or (b) of 

this section. 

(a) Calculate and report under this subpart the 

process CO2 emissions by operating and maintaining a CEMS 

according to the Tier 4 Calculation Methodology specified 

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

in subpart C of this part (General Stationary Fuel 

Combustion Sources). 

(b) Calculate and report under this subpart the 

process CO2 emissions using the procedures in paragraphs 

(b)(1) and (b)(2) of this section. 

(1) Calculate and report the process CO2 emissions 

from each wet-process phosphoric acid process line using 

Equation Z-1 of this section: 

12

44 *

2205

2000 ( * ) *

1 1

∑∑ , ,

= =

=

b

i

z

n

m n i Pn i E IC (Eq. Z-1) 

Where: 

Em = Annual CO2 mass emissions from a wet-process 

phosphoric acid process line m (metric 

tons). 

ICn,i = Inorganic carbon content of a grab sample 

batch of phosphate rock by origin i 

obtained during month n, from the carbon 

analysis results (percent by weight, 

expressed as a decimal fraction). 

Pn,i = Mass of phosphate rock by origin i consumed in 

month n by wet-process phosphoric acid 

process line m (tons). 

z = Number of months during which the process line 

m operates. 
253

b = Number of different types of phosphate rock in 

month, by origin. If the grab sample is a 

composite sample of rock from more than one 

origin, b=1. 

2000/2205 = Conversion factor to convert tons to metric 

tons. 

44/12 = Ratio of molecular weights, CO2 to carbon. 

(2) You must determine the total emissions from the 

facility using Equation Z-2 of this section: 

∑=

=

p

m

CO Em

1

2 (Eq. Z-2) 

Where: 

CO2 = Annual process CO2 emissions from phosphoric 

acid production facility (metric tons/year) 

Em = Annual process CO2 emissions from wet-process 

phosphoric acid process line m (metric 

tons/year) 

p = Number of wet-process phosphoric acid process 

lines. 

(c) If GHG emissions from a wet-process phosphoric 

acid process line are vented through the same stack as any 

combustion unit or process equipment that reports CO2

emissions using a CEMS that complies with the Tier 4 

Calculation Methodology in subpart C of this part (General 

Stationary Fuel Combustion Sources), then the calculation 

methodology in paragraph (b) of this section shall not be 

used to calculate process emissions. The owner or operator 

shall report under this subpart the combined stack 

emissions according to the Tier 4 Calculation Methodology 
254

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

in subpart C of this part. 

§98.264 Monitoring and QA/QC requirements.

(a) You must obtain a monthly grab sample of 

phosphate rock directly from the rock being fed to the 

process line before it enters the mill. Conduct the 

representative bulk sampling using the appropriate industry 

consensus standard or applicable standard method in the 

Association of Fertilizer and Phosphate Chemists Analytical 

Methods Manual 10th Edition (incorporated by reference, see 

§98.7). If phosphate rock is obtained from more than one 

origin in a month, you must obtain a sample from each 

origin of rock or obtain a composite representative sample. 

(b) You must determine the inorganic carbon content 

of each monthly grab sample of phosphate rock (consumed in 

the production of phosphoric acid) using the applicable 

standard method in the Association of Fertilizer and 

Phosphate Chemists Analytical Methods Manual 10th Edition

(incorporated by reference, see §98.7). 

(c) You must determine the mass of phosphate rock 

consumed each month (by origin) in each wet-process 

phosphoric acid process line. You can use existing plant 

procedures that are used for accounting purposes (such as 

sales records) or you can use data from existing monitoring 

Deleted: Phosphate Mining 

States Methods Used and 

Adopted by the 

Deleted: AFPC Manual 10th 

Edition 2009 - Version 1.9 

Deleted: Phosphate Mining 

States Methods Used and 

Adopted by the 

Deleted: AFPC Manual 10th 

Edition 2009 - Version 1.9 
255

equipment that is used to measure total mass flow of 

phosphorous-bearing feed under 40 CFR part 60 or part 63. 

§98.265 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations in §98.263(b) is required. 

Therefore, whenever a quality-assured value of a required 

parameter is unavailable, a substitute data value for the 

missing parameter shall be used in the calculations as 

specified in paragraphs (a) and (b) of this section. You 

must document and keep records of the procedures used for 

all such estimates. 

(a) For each missing value of the inorganic carbon 

content of phosphate rock (by origin), you must use the 

appropriate default factor provided in Table Z-1 of this 

subpart. Alternatively, you must determine substitute 

data value by calculating the arithmetic average of the 

quality-assured values of inorganic carbon contents of 

phosphate rock of origin i from samples immediately 

preceding and immediately following the missing data 

incident. If no quality-assured data on inorganic carbon 

contents of phosphate rock of origin i are available prior 

to the missing data incident, the substitute data value 

shall be the first quality-assured value for inorganic 

Deleted: the
256

carbon contents for phosphate rock of origin i obtained 

after the missing data period. 

(b) For each missing value of monthly mass 

consumption of phosphate rock (by origin), you must use the 

best available estimate based on all available process data 

or data used for accounting purposes. 

§98.266 Data reporting requirements. 

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

each annual report must contain the information specified 

in paragraphs (a) through (f) of this section. 

(a) Annual phosphoric acid production by origin (as 

listed in Table Z-1 to this subpart) of the phosphate rock 

(tons). 

(b) Annual phosphoric acid permitted production 

capacity (tons). 

(c) Annual arithmetic average percent inorganic 

carbon in phosphate rock from monthly records (percent by 

weight, expressed as a decimal fraction). 

(d) Annual phosphate rock consumption from monthly 

measurement records by origin, (as listed in Table Z-1 to 

this subpart) (tons). 

(e) If you use a CEMS to measure CO2 emissions, then 

you must report the information in paragraphs (e)(1) and 

(e)(2) of this section. 

Deleted: b
257

(1) The identification number of each wet-process 

phosphoric acid process line. 

(2) The annual CO2 emissions from each wet-process 

phosphoric acid process line (metric tons) and the relevant 

information required under 40 CFR 98.36 (e)(2)(vi) for the 

Tier 4 Calculation Methodology. 

(f) If you do not use a CEMS to measure emissions, 

then you must report the information in paragraphs (f)(1) 

through (f)(9) of this section. 

(1) Identification number of each wet-process 

phosphoric acid process line. 

(2) Annual CO2 emissions from each wet-process 

phosphoric acid process line (metric tons) as calculated by 

Equation Z-1 of this subpart. 

(3) Annual phosphoric acid permitted production 

capacity (tons) for each wet-process phosphoric acid 

process line (metric tons). 

(4) Method used to estimate any missing values of 

inorganic carbon content of phosphate rock for each wetprocess phosphoric acid process line. 

(5) Monthly inorganic carbon content of phosphate 

rock for each wet-process phosphoric acid process line 

(percent by weight, expressed as a decimal fraction). 

Deleted: 8
258

(6) Monthly mass of phosphate rock consumed by 

origin, (as listed in Table Z-1 of this subpart) in 

production for each wet-process phosphoric acid process 

line (tons). 

(7) Number of wet-process phosphoric acid process 

lines. 

(8) Number of times missing data procedures were used 

to estimate phosphate rock consumption (months) and 

inorganic carbon contents of the phosphate rock (months). 

(9) Annual process CO2 emissions from phosphoric acid 

production facility (metric tons). 

§98.267 Records that must be retained.

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

must retain the records specified in paragraphs (a) through 

(c) of this section for each wet-process phosphoric acid 

production facility. 

(a) Monthly mass of phosphate rock consumed by origin 

(as listed in Table Z-1 of this subpart) (tons). 

(b) Records of all phosphate rock purchases and/or 

deliveries (if vertically integrated with a mine). 

(c) Documentation of the procedures used to ensure 

the accuracy of monthly phosphate rock consumption by 

origin, (as listed in Table Z-1 of this subpart). 

§98.268 Definitions.
259

All terms used in this subpart have the same meaning 

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

Table Z-1 of Subpart Z—Default Chemical Composition of 

Phosphate Rock by Origin 

Origin Total Carbon 

(percent by weight) 

Central Florida 1.6 

North Florida 1.76 

North Carolina (Calcined) 0.76 

Idaho (Calcined) 0.60 

Morocco 1.56 

Subpart CC—Soda Ash Manufacturing 

§98.290 Definition of the source category.

(a) A soda ash manufacturing facility is any facility 

with a manufacturing line that produces soda ash by one of 

the methods in paragraphs (a) through (c) of this section: 

(1) Calcining trona. 

(2) Calcining sodium sesquicarbonate. 

(3) Using a liquid alkaline feedstock process that 

directly produces CO2. 

(b) In the context of the soda ash manufacturing 

sector, “calcining” means the thermal/chemical conversion 

of the bicarbonate fraction of the feedstock to sodium 

carbonate. 

§98.291 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a soda ash manufacturing process and 
260

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

or (a)(2). 

§98.292 GHGs to report.

You must report: 

(a) CO2 process emissions from each soda ash 

manufacturing line combined. 

(b) CO2 combustion emissions from each soda ash 

manufacturing line. 

(c) CH4 and N2O combustion emissions from each soda 

ash manufacturing line. You must calculate and report 

these emissions under subpart C of this part (General 

Stationary Fuel Combustion Sources) by following the 

requirements of subpart C. 

(d) CO2, CH4, and N2O emissions from each stationary 

combustion unit other than soda ash manufacturing lines. 

You must calculate and report these emissions under subpart 

C of this part (General Stationary Fuel Combustion Sources) 

by following the requirements of subpart C. 

§98.293 Calculating GHG emissions.

You must calculate and report the annual process CO2

emissions from each soda ash manufacturing line using the 

procedures specified in paragraph (a) or (b) of this 

section. 
261

(a) For each soda ash manufacturing line that meets 

the conditions specified in §98.33(b)(4)(ii) or 

(b)(4)(iii), you must calculate and report under this 

subpart the combined process and combustion CO2 emissions by 

operating and maintaining a CEMS to measure CO2 emissions 

according to the Tier 4 Calculation Methodology specified 

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

in subpart C of this part (General Stationary Fuel 

Combustion Sources). 

(b) For each soda ash manufacturing line that is not 

subject to the requirements in paragraph (a) of this 

section, calculate and report the process CO2 emissions from 

the soda ash manufacturing line by using the procedure in 

either paragraphs (b)(1), (b)(2), or (b)(3) of this 

section; and the combustion CO2 emissions using the 

procedure in paragraph (b)(4) of this section. 

(1) Calculate and report under this subpart the 

combined process and combustion CO2 emissions by operating 

and maintaining a CEMS to measure CO2 emissions according to 

the Tier 4 Calculation Methodology specified in 

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

subpart C of this part (General Stationary Fuel Combustion 

Sources). 
262

(2) Use either Equation CC-1 or Equation CC-2 of this 

section to calculate annual CO2 process emissions from each 

manufacturing line that calcines trona to produce soda ash: 

( ) ( )

1

0.097 *

2205

2000 E [ IC * T ] *

12

n 1

k ∑ T n t n

=

= (Eq. CC-1) 

( ) ( )

1

0.138

2205

2000 E [ IC * T ]* *

12

n 1

k ∑ sa n sa n

=

= (Eq. CC-2) 

Where: 

Ek = Annual CO2 process emissions from each 

manufacturing line, k (metric tons). 

(ICT)n = Inorganic carbon content (percent by weight, 

expressed as a decimal fraction) in trona 

input, from the carbon analysis results for 

month n. This represents the ratio of trona 

to trona ore. 

(ICsa)n = Inorganic carbon content(percent by weight, 

expressed as a decimal fraction) in soda ash 

output, from the carbon analysis results for 

month n. This represents the purity of the 

soda ash produced. 

(Tt)n = Mass of trona input in month n (tons). 

(Tsa)n = Mass of soda ash output in month n (tons). 

2000/2205 = Conversion factor to convert tons to metric 

tons. 

0.097/1 = Ratio of ton of CO2 emitted for each ton of 

trona. 

0.138/1 = Ratio of ton of CO2 emitted for each ton of 

soda ash produced. 

(3) Site-specific emission factor method. Use 

Equations CC-3, CC-4, and CC-5 of this section to determine 

annual CO2 process emissions from manufacturing lines that 

use the liquid alkaline feedstock process to produce soda 

ash. You must conduct an annual performance test and 
263

measure CO2 emissions and flow rates at all process vents 

from the mine water stripper/evaporator for each 

manufacturing line and calculate CO2 emissions as described 

in paragraphs (b)(3)(i) through (b)(3)(iv) of this section. 

(i) During the performance test, you must measure the 

process vent flow from each process vent during the test 

and calculate the average rate for the test period in 

metric tons per hour. 

(ii) Using the test data, you must calculate the 

hourly CO2 emission rate using Equation CC-3 of this 

section: 

9 4

2

2

[( *10000) * 2.59 10 * 44]* ( * 60) * 4.53 10 − − ER = Cco x Q x CO (Eq. CC-3) 

Where: 

ERCO2 = CO2 mass emission rate (metric tons/hour). 

CCO2 = Hourly CO2 concentration (percent CO2) as 

determined by §98.294(c). 

10000 = Parts per million per percent 

2.59 x 10-9 = Conversion factor (pounds-mole/dscf/ppm). 

44 = Pounds per pound-mole of carbon dioxide. 

Q = Stack gas volumetric flow rate per minute 

(dscfm). 

60 = Minutes per hour 

4.53 x 10-4 = Conversion factor (metric tons/pound) 

(iii) Using the test data, you must calculate a CO2

emission factor for the process using Equation CC-4 of this 

section: 
264

( * 4.53 10 )

4

2

2 −

=

V x

ER EF

t

CO

CO (Eq. CC-4) 

Where: 

EFCO2 = CO2 emission factor (metric tons CO2/metric 

ton of process vent flow from mine water 

stripper/evaporator). 

ERCO2 = CO2 mass emission rate (metric tons/hour). 

Vt = Process vent flow rate from mine water 

stripper/evaporator during annual 

performance test (pounds/hour). 

4.53 x 10-4 = Conversion factor (metric tons/pound) 

(iv) You must calculate annual CO2 process emissions 

from each manufacturing line using Equation CC-5 of this 

section: 

Ek = EFCO2 *(Va *0.453) * H (Eq. CC-5) 

Where: 

Ek = Annual CO2 process emissions for each 

manufacturing line, k (metric tons). 

EFCO2 = CO2 emission factor (metric tons CO2/metric 

ton of process vent flow from mine water 

stripper/evaporator). 

Va = Annual process vent flow rate from mine water 

stripper/evaporator (thousand pounds/hour). 

H = Annual operating hours for the each 

manufacturing line. 

0.453 = Conversion factor (metric tons/thousand 

pounds). 

(4) Calculate and report under subpart C of this part 

(General Stationary Fuel Combustion Sources) the combustion 
265

CO2, CH4, and N2O emissions in the soda ash manufacturing 

line according to the applicable requirements in subpart C. 

§98.294 Monitoring and QA/QC requirements.

Section 98.293 provides three different procedures for 

emission calculations. The appropriate paragraphs (a) 

through (c) should be used for the procedure chosen. 

(a) If you determine your emissions using 

§98.293(b)(2) (Equation CC-1 of this subpart) you must: 

(1) Determine the monthly inorganic carbon content of 

the trona from a weekly composite analysis for each soda 

ash manufacturing line, using a modified version of ASTM 

E359-00(Reapproved 2005)e1, Standard Test Methods for 

Analysis of Soda Ash (Sodium Carbonate) (incorporated by 

reference, see §98.7). ASTM E359-00(Reapproved 2005)e1 is 

designed to measure the total alkalinity in soda ash not in 

trona. The modified method referred to above adjusts the 

regular ASTM method to express the results in terms of 

trona. Although ASTM E359-00(Reapproved 2005)e1 uses manual 

titration, suitable autotitrators may also be used for this 

determination. 

(2) Measure the mass of trona input produced by each 

soda ash manufacturing line on a monthly basis using belt 

scales or methods used for accounting purposes. 

Deleted: of ASTM E359-00
266

(3) Document the procedures used to ensure the 

accuracy of the monthly measurements of trona consumed. 

(b) If you calculate CO2 process emissions based on 

soda ash production (§98.293(b)(2)Equation CC-2 of this 

subpart), you must: 

(1) Determine the inorganic carbon content of the 

soda ash (i.e., soda ash purity) using ASTM E359-

00(Reapproved 2005)e1 Standard Test Methods for Analysis of 

Soda Ash (Sodium Carbonate) (incorporated by reference, see 

§98.7). Although ASTM E359-00(Reapproved 2005)e1 uses 

manual titration, suitable autotitrators may also be used 

for this determination. 

(2) Measure the mass of soda ash produced by each 

soda ash manufacturing line on a monthly basis using belt 

scales, by weighing the soda ash at the truck or rail 

loadout points of your facility, or methods used for 

accounting purposes. 

(3) Document the procedures used to ensure the 

accuracy of the monthly measurements of soda ash produced. 

(c) If you calculate CO2 emissions using the sitespecific emission factor method in §98.293(b)(3), you must: 

(1) Conduct an annual performance test that is based 

on representative performance (i.e., performance based on 

normal operating conditions) of the affected process. 
267

(2) Sample the stack gas and conduct three emissions 

test runs of 1 hour each. 

(3) Conduct the stack test using EPA Method 3A at 40 

CFR part 60, appendix A-2 to measure the CO2 concentration, 

Method 2, 2A, 2C, 2D, or 2F at 40 CFR part 60, appendix A-1 

or Method 26 at 40 CFR part 60, appendix A-2 to determine 

the stack gas volumetric flow rate. All QA/QC procedures 

specified in the reference test methods and any associated 

performance specifications apply. For each test, the 

facility must prepare an emission factor determination 

report that must include the items in paragraphs (c)(3)(i) 

through (c)(3)(iii) of this section. 

(i) Analysis of samples, determination of emissions, 

and raw data. 

(ii) All information and data used to derive the 

emissions factor(s). 

(iii) You must determine the average process vent 

flow rate from the mine water stripper/evaporater during 

each test and document how it was determined. 

(4) You must also determine the the annual vent flow 

rate from the mine water stripper/evaporater from monthly 

information using the same plant instruments or procedures 

used for accounting purposes (i.e., volumetric flow meter). 

§98.295 Procedures for estimating missing data.
268

For the emission calculation methodologies in 

§98.293(b)(2)and (b)(3), a complete record of all measured 

parameters used in the GHG emissions calculations is 

required (e.g., inorganic carbon content values, etc.). 

Therefore, whenever a quality-assured value of a required 

parameter is unavailable, a substitute data value for the 

missing parameter shall be used in the calculations as 

specified in the paragraphs (a) through (d) of this 

section. You must document and keep records of the 

procedures used for all such missing value estimates. 

(a) For each missing value of the weekly composite of 

inorganic carbon content of either soda ash or trona, the 

substitute data value shall be the arithmetic average of 

the quality-assured values of inorganic carbon contents 

from the week immediately preceding and the week 

immediately following the missing data incident. If no 

quality-assured data on inorganic carbon contents are 

available prior to the missing data incident, the 

substitute data value shall be the first quality-assured 

value for carbon contents obtained after the missing data 

period. 

(b) For each missing value of either the monthly soda 

ash production or the trona consumption, the substitute 

data value shall shall be the best available estimate(s) of 
269

the parameter(s), based on all available process data or 

data used for accounting purposes. 

(c) For each missing value collected during the 

performance test (hourly CO2 concentration, stack gas 

volumetric flow rate, or average process vent flow from 

mine water stripper/evaporator during performance test), 

you must repeat the annual performance test following the 

calculation and monitoring and QA/QC requirements under 

§§98.293(b)(3) and 98.294(c). 

(d) For each missing value of the monthly process 

vent flow rate from mine water stripper/evaporator, the 

subsititute data value shall be the best available 

estimate(s) of the parameter(s), based on all available 

process data or the lesser of the maximum capacity of the 

system or the maximum rate the meter can measure. 

§98.296 Data reporting requirements. 

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

each annual report must contain the information specified 

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

for each soda ash manufacturing facility. 

(a) If a CEMS is used to measure CO2 emissions, then 

you must report under this subpart the relevant information 

required under §98.36 and the following information in this 

paragraph (a): 
270

(1) Annual consumption of trona or liquid alkaline 

feedstock for each manufacturing line (tons). 

(2) Annual production of soda ash for each 

manufacturing line (tons). 

(3) Annual production capacity of soda ash for each 

manufacturing line (tons). 

(4) Identification number of each manufacturing line. 

(b) If a CEMS is not used to measure CO2 emissions, 

then you must report the information listed in this 

paragraph (b): 

(1) Identification number of each manufacturing line. 

(2) Annual process CO2 emissions from each soda ash 

manufacturing line (metric tons). 

(3) Annual production of soda ash for each 

manufacturing line (tons). 

(4) Annual production capacity of soda ash for each 

manufacturing line (tons). 

(5) Monthly consumption of trona or liquid alkaline 

feedstock for each manufacturing line (tons). 

(6) Monthly production of soda ash for each 

manufacturing line (tons). 

(7) Inorganic carbon content factor of trona or soda 

ash (depending on use of Equations CC-1 or CC-2 of this 

subpart) as measured by the applicable method in §98.294(b) 

Deleted: metric 

Deleted: metric 
271

or (c) for each month (percent by weight expressed as a 

decimal fraction). 

(8) Whether CO2 emissions for each manufacturing line 

were calculated using a trona input method as described in 

Equation CC-1 of this subpart, a soda ash output method as 

described in Equation CC-2 of this subpart, or a sitespecific emission factor method as described in Equations 

CC-3 through CC-5 of this subpart. 

(9) Number of manufacturing lines located used to 

produce soda ash. 

(10) If you produce soda ash using the liquid 

alkaline feedstock process and use the site-specific 

emission factor method (§98.293(b)(3)) to estimate 

emissions then you must report the following relevant 

information for each manufacturing line or stack: 

(i) Stack gas volumetric flow rate during performance 

test (dscfm).

(ii) Hourly CO2 concentration during performance test

(percent CO2).

(iii) CO2 emission factor (metric tons CO2/metric tons 

of process vent flow from mine water stripper/evaporator). 

(iv) CO2 mass emission rate during performance test

(metric tons/hour). 

Deleted: per minute
272

(v) Average process vent flow from mine water 

stripper/evaporater during performance test (pounds/hour). 

(vi) Annual process vent flow rate from mine 

stripper/evaporator (thousand pounds/hour). 

(vii) Annual operating hours for each manufacturing 

line used to produce soda ash using liquid alkaline 

feedstock (hours). 

(11) Number of times missing data procedures were 

used and for which parameter as specified in this paragraph 

(b)(11): 

(i) Trona or soda ash (number of months). 

(ii) Inorganic carbon contents of trona or soda ash 

(weeks). 

(iii) Process vent flow rate from mine water 

stripper/evaporator (number of months). 

§98.297 Records that must be retained. 

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

must retain the records specified in paragraphs (a) and (b) 

of this section for each soda ash manufacturing line. 

(a) If a CEMS is used to measure CO2 emissions, then 

you must retain under this subpart the records required for 

the Tier 4 Calculation Methodology specified in subpart C 

of this part and the information listed in this paragraph 

(a): 

Deleted: ¶

(iv) Stack gas volumetric 

flow rate during performance 

test(number of times).¶

(v) Hourly CO2

concentration (number of 

times). ¶

(vi) Average vent process 

vent flow rate from mine 

stripper/evaporator during 

performance test (number of 

times). 
273

(1) Monthly production of soda ash (tons) 

(2) Monthly consumption of trona or liquid alkaline 

feedstock (tons) 

(3) Annual operating hours (hours). 

(b) If a CEMS is not used to measure emissions, then 

you must retain records for the information listed in this 

paragraph (b): 

(1) Records of all analyses and calculations 

conducted for determining all reported data as listed in 

§98.296(b). 

(2) If using Equation CC-1 or CC-2 of this subpart, 

weekly inorganic carbon content factor of trona or soda 

ash, depending on method chosen, as measured by the 

applicable method in §98.294(b)(percent by weight expressed 

as a decimal fraction). 

(3) Annual operating hours for each manufacturing 

line used to produce soda ash (hours). 

(4) You must document the procedures used to ensure 

the accuracy of the monthly trona consumption or soda ash 

prodcution measurements including, but not limited to, 

calibration of weighing equipment and other measurement 

devices. The estimated accuracy of measurements made with 

these devices must also be recorded, and the technical 

basis for these estimates must be provided. 
274

(5) If you produce soda ash using the liquid alkaline 

feedstock process and use the site-specific emission factor 

method to estimate emissions (§98.293(b)(3)) then you must 

also retain the following relevant information: 

(i) Records of performance test results. 

(ii) You must document the procedures used to ensure 

the accuracy of the annual average vent flow measurements 

including, but not limited to, calibration of flow rate 

meters and other measurement devices. The estimated 

accuracy of measurements made with these devices must also 

be recorded, and the technical basis for these estimates 

must be provided. 

§98.298 Definitions.

All terms used in this subpart have the same meaning 

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

Subpart EE—Titanium Dioxide Production 

§98.310 Definition of the source category.

The titanium dioxide production source category 

consists of facilities that use the chloride process to 

produce titanium dioxide. 

§98.311 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a titanium dioxide production 
275

process and the facility meets the requirements of either 

§98.2(a)(1) or (a)(2). 

§98.312 GHGs to report.

(a) You must report CO2 process emissions from each 

chloride process line as required in this subpart. 

(b) You must report under 40 CFR 98, CO2, CH4, and N20 

emissions from each stationary combustion unit under 

subpart C of this part (General Stationary Fuel Combustion 

Sources) by following the requirements of subpart C. 

§98.313 Calculating GHG emissions.

You must calculate and report the annual process CO2

emissions for each chloride process line using the 

procedures in either paragraph (a) or (b) of this section. 

(a) Calculate and report under this subpart the 

process CO2 emissions by operating and maintaining a CEMS 

according to the Tier 4 Calculation Methodology specified 

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

in subpart C of this part (General Stationary Fuel 

Combustion Sources). 

(b) Calculate and report under this subpart the 

annual process CO2 emissions for each chloride process line 

by determining the mass of calcined petroleum coke consumed 

in each line as specified in paragraphs (b)(1) through 

(b)(3) of this section. Use Equation EE-1 of this section 
276

to calulate annual combined process CO2 emissions from all 

process lines and use Equation EE-2 of this section to 

calculate annual process CO2 emissions for each process 

line. If your facility generates carbon-containing waste, 

use Equation EE-3 of this section to estimate the annual 

quantity of carbon-containing waste generated and its 

carbon contents according to §98.314(e) and (f): 

(1) You must calculate the annual CO2 process 

emissions from all process lines at the facility using 

Equation EE-1 of this section: 

∑=

=

m

p

CO Ep

1

2 (Eq. EE-1) 

Where: 

CO2 = Annual CO2 emissions from titanium dioxide 

production facility (metric tons/year). 

Ep = Annual CO2 emissions from chloride process line p 

(metric tons), determined using Equation EE-2 of 

this section. 

p = Process line. 

m = Number of separate chloride process lines located 

at the facility. 

(2) You must calculate the annual CO2 process 

emissions from each process lines at the facility using 

Equation EE-2 of this section: 

n

n

Ep Cp n*CCF

2205

2000 * *

12

44 12

1

∑ ,

=

= (Eq. EE-2) 

Where: 
277

Ep = Annual CO2 mass emissions from chloride process 

line p (metric tons). 

Cp,n = Calcined petroleum coke consumption for process 

line p in month n (tons). 

44/12 = Ratio of molecular weights, CO2 to carbon. 

2000/2205 = Conversion of tons to metric tons. 

CCFn = Carbon content factor for petroleum coke 

consumed in month n from the supplier or as 

measured by the applicable method incorporated 

by reference in §98.7 according to §98.314(c) 

(percent by weight expressed as a decimal 

fraction). 

n = Number of month. 

(3) If facility generates carbon-containing waste, 

you must calculate the total annual quantity of carboncontaining waste produced from all process lines using 

Equation EE-3 of this section and its carbon contents 

according to §98.314(e) and (f): 

∑ ∑ = =

= =

12

1

,

1

1

n

p n

m

p

TWC n WC (Eq. EE-3) 

Where: 

TWC = Annual production of carbon-containing waste 

from titanium dioxide production facility 

(tons). 

WCp,n = Production of carbon-containing waste in month n 

from chloride process line p (tons). 

p = Process line. 

m = Total number of process lines. 

n = Number of month. 

(c) If GHG emissions from a chloride process line are 

vented through the same stack as any combustion unit or 
278

process equipment that reports CO2 emissions using a CEMS 

that complies with the Tier 4 Calculation Methodology in 

subpart C of this part (General Stationary Fuel Combustion 

Sources), then the calculation methodology in paragraph (b) 

of this section shall not be used to calculate process CO2 

emissions. The owner or operator shall report under this 

subpart the combined stack emissions according to the Tier 

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

associated requirements for Tier 4 in subpart C of this 

part. 

§98.314 Monitoring and QA/QC requirements. 

(a) You must measure your consumption of calcined 

petroleum coke using plant instruments used for accounting 

purposes including direct measurement weighing the 

petroleum coke fed into your process (by belt scales or a 

similar device) or through the use of purchase records. 

(b) You must document the procedures used to ensure 

the accuracy of monthly calcined petroleum coke consumption 

measurements. 

(c) You must determine the carbon content of the 

calcined petroleum coke each month based on reports from 

the supplier. Alternatively, facilities can measure 

monthly carbon contents of the petroleum coke using ASTM 

D3176-89 (Reapproved 2002) Standard Practice for Ultimate 
279

Analysis of Coal and Coke (incorporated by reference, see 

§98.7) and ASTM D5373-08 Standard Test Methods for 

Instrumental Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal (incorporated by 

reference, see §98.7). 

(d) For quality assurance and quality control of the 

supplier data, you must conduct an annual measurement of 

the carbon content from a representative sample of the 

petroleum coke consumed using ASTM D3176-89 and ASTM D5373-

08. 

(e) You must determine the quantity of carboncontaining waste generated from each titanium dioxide

production line on a monthly basis using plant instruments 

used for accounting purposes including direct measurement 

weighing the carbon-containing waste not used during the 

process (by belt scales or a similar device) or through the 

use of sales records. 

(f) You must determine the carbon contents of the 

carbon-containing waste from each titanium production line 

on an annual basis by collecting and analyzing a 

representative sample of the material using ASTM D3176-89 

and ASTM D5373-08. 

§98.315 Procedures for estimating missing data.

Deleted: the

Deleted: dioxide
280

For the petroleum coke input procedure in §98.313(b), 

a complete record of all measured parameters used in the 

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

content values, etc.). Therefore, whenever the monitoring 

and quality assurance procedures in §98.315 cannot be 

followed, a substitute data value for the missing parameter 

shall be used in the calculations as specified in the 

paragraphs (a) through (c) of this section. You must 

document and keep records of the procedures used for all 

such estimates. 

(a) For each missing value of the monthly carbon 

content of calcined petroleum coke the substitute data 

value shall be the arithmetic average of the qualityassured values of carbon contents for the month immediately 

preceding and the month immediately following the missing 

data incident. If no quality-assured data on carbon 

contents are available prior to the missing data incident, 

the substitute data value shall be the first qualityassured value for carbon contents obtained after the 

missing data period. 

(b) For each missing value of the monthly calcined 

petroleum coke consumption and/or carbon-containing waste, 

the substitute data value shall be the best available 

estimate of the monthly petroleum coke consumption based on 
281

all available process data or information used for 

accounting purposes (such as purchase records). 

(c) For each missing value of the carbon content of 

carbon-containing waste, you must conduct a new analysis 

following the procedures in §98.314(f). 

§98.316 Data reporting requirements. 

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

each annual report must contain the information specified 

in paragraphs (a) or (b) of this section, as applicable for 

each titanium dioxide production line. 

(a) If a CEMS is used to measure CO2 emissions, then 

you must report the relevant information required under 

§98.36(e)(2)(vi) for the Tier 4 Calculation Methodology and 

the following information in this paragraph (a). 

(1) Identification number of each process line. 

(2) Annual consumption of calcined petroleum coke 

(tons). 

(3) Annual production of titanium dioxide (tons). 

(4) Annual production capacity of titanium dioxide 

(tons). 

(5) Annual production of carbon-containing waste 

(tons), if applicable. 
282

(b) If a CEMS is not used to measure CO2 emissions, 

then you must report the information listed in this 

paragraph (b): 

(1) Identification number of each process line. 

(2) Annual CO2 emissions from each chloride process 

line (metric tons/year). 

(3) Annual consumption of calcined petroleum coke for 

each process line (tons). 

(4) Annual production of titanium dioxide for each 

process line (tons). 

(5) Annual production capacity of titanium dioxide 

for each process line (tons). 

(6) Calcined petroleum coke consumption for each 

process line for each month (tons). 

(7) Annual production of carbon-containing waste for 

each process line (tons), if applicable. 

(8) Monthly production of titanium dioxide for each 

process line (tons). 

(9) Monthly carbon content factor of petroleum coke 

(percent by weight expressed as a decimal fraction). 

(10) Whether monthly carbon content of the petroleum 

coke is based on reports from the supplier or through self 

measurement using applicable ASTM standard methods. 

Deleted: from the supplier 
283

(11) Carbon content for carbon-containing waste for 

each process line (percent by weight expressed as a decimal 

fraction). 

(12) If carbon content of petroleum coke is based on 

self measurement, the ASTM standard methods used. 

(13) Sampling analysis results of carbon content of 

petroleum coke as determined for QA/QC of supplier data 

under §98.314(d) (percent by weight expressed as a decimal 

fraction). 

(14) Number of separate chloride process lines 

located at the facility. 

(15) The number of times in the reporting year that 

missing data procedures were followed to measure the carbon 

contents of petroleum coke (number of months); petroleum 

coke consumption (number of months); carbon-containing 

waste generated (number of months); and carbon contents of 

the carbon-containing waste (number of times during year). 

§98.317 Records that must be retained. 

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

must retain the records specified in paragraphs (a) and (b) 

of this section for each titanium dioxide production 

facility. 

(a) If a CEMS is used to measure CO2 emissions, then 

you must retain under this subpart required for the Tier 4 
284

Calculation Methodology in §98.37 and the information 

listed in this paragraph (a): 

(1) Records of all calcined petroleum coke purchases. 

(2) Annual operating hours for each titanium dioxide 

process line. 

(b) If a CEMS is not used to measure CO2 emissions, 

then you must retain records for the information listed in 

this paraghraph: 

(1) Records of all calcined petroleum coke purchases 

(tons). 

(2) Records of all analyses and calculations 

conducted for all reported data as listed in §98.316(b). 

(3) Sampling analysis results for carbon content of 

consumed calcined petroleum coke (percent by weight 

expressed as a decimal fraction). 

(4) Sampling analysis results for the carbon content 

of carbon containing waste (percent by weight expressed as 

a decimal fraction), if applicable. 

(5) Monthly production of carbon-containing waste 

(tons). 

(6) You must document the procedures used to ensure 

the accuracy of the monthly petroleum coke consumption and 

quantity of carbon-containing waste measurement including, 

but not limited to, calibration of weighing equipment and 
285

other measurement devices. The estimated accuracy of 

measurements made with these devices must also be recorded, 

and the technical basis for these estimates must be 

provided. 

(7) Annual operating hours for each titanium dioxide 

process line (hours). 

§98.318 Definitions.

All terms used in this subpart have the same meaning 

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

Subpart GG—Zinc Production 

§98.330 Definition of the source category.

The zinc production source category consists of zinc 

smelters and secondary zinc recycling facilities. 

§98.331 Reporting threshold. 

You must report GHG emissions under this subpart if 

your facility contains a zinc production process and the 

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

(2). 

§98.332 GHGs to report.

You must report: 

(a) CO2 process emissions from each Waelz kiln and 

electrothermic furnace used for zinc production. 

(b) CO2, CH4, and N2O combustion emissions from each 

Waelz kiln. You must calculate and report these emissions 
286

under subpart C of this part (General Stationary Fuel 

Combustion Sources) by following the requirements of 

subpart C. 

(c) CO2, CH4, and N2O emissions from each stationary 

combustion unit other than Waelz kilns. You must report 

these emissions under subpart C of this part (General 

Stationary Fuel Combustion Sources) by following the 

requirements of subpart C. 

§98.333 Calculating GHG emissions.

You must calculate and report the annual process CO2

emissions using the procedures specified in either 

paragraph (a) or (b) of this section. 

(a) Calculate and report under this subpart the 

process or combined process and combustion CO2 emissions by 

operating and maintaining a CEMS according to the Tier 4 

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

requirements for Tier 4 in subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(b) Calculate and report under this subpart the 

process CO2 emissions by following paragraphs (b)(1) and 

(b)(2) of this section. 

(1) For each Waelz kiln or electrothermic furnace at 

your facility used for zinc production, you must determine 

the mass of carbon in each carbon-containing material, 
287

other than fuel, that is fed, charged, or otherwise 

introduced into each Waelz kiln and electrothermic furnace 

at your facility for each year and calculate annual CO2 

process emissions from each affected unit at your facility 

using Equation GG-1 of this section. For electrothermic 

furnaces, carbon containing input materials include carbon 

eletrodes and carbonaceous reducing agents. For Waelz 

kilns, carbon containing input materials include 

carbonaceous reducing agents. If you document that a 

specific material contributes less than 1 percent of the 

total carbon into the process, you do not have to include 

the material in your calculation using Equation R-1 of 

§98.183. 

( ) ( ) ( ) ( )

+ ( ) * ( ) + ( ) * ( ) ]

* [ * + *

2205

2000

*

12

44

E CO2k =

k

carbon k kElectrode k

k

Flux k kZinc k

Electrode C Carbon C

Zinc C Flux C

(Eq. GG-1) 

Where: 

ECO2k = Annual CO2 process emissions from 

individual Waelz kiln or electrothermic 

furnace “k” (metric tons). 

44/12 = Ratio of molecular weights, CO2 to carbon. 

2000/2205 = Conversion factor to convert tons to 

metric tons. 

(Zinc)k = Annual mass of zinc bearing material 

charged to kiln or furnace ”k” (tons). 

(CZinc)k = Carbon content of the zinc bearing 

material, from the annual carbon analysis 

for kiln or furnace “k” (percent by 

weight, expressed as a decimal fraction).
288

(Flux)k = Annual mass of flux materials (e.g., 

limestone, dolomite) charged to kiln or 

furnace “k” (tons). 

(CFlux) k = Carbon content of the flux materials 

charged to kiln or furnace “k”, from the 

annual carbon analysis (percent by weight, 

expressed as a decimal fraction). 

(Electrode)k = Annual mass of carbon electrode consumed 

in furnace “k” (tons). 

(CElectrode)k = Carbon content of the carbon electrode 

consumed in furnace “k”, from the annual 

carbon analysis (percent by weight, 

expressed as a decimal fraction). 

(Carbon)k = Annual mass of carbonaceous materials 

(e.g., coal, coke) charged to the kiln or 

furnace “k”(tons). 

(CCarbon) k Carbon content of the carbonaceous 

materials charged to kiln or furnace, “k”, 

from the annual carbon analysis (percent 

by weight, expressed as a decimal 

fraction). 

(2) You must determine the CO2 emissions from all of 

the Waelz kilns or electrothermic furnaces at your facility 

using Equation GG-2 of this section. 

∑=

=

n

k 1

CO2 E CO2 k (Eq. GG-2) 

Where: 

CO2 = Annual combined CO2 emissions from all Waelz 

kilns or electrothermic furnaces (tons). 

ECO2k= Annual CO2 emissions from each Waelz kiln or 

electrothermic furnace k calculated using 

Equation GG-1 of this section (tons). 

n = Total number of Waelz kilns or electrothermic 

furnaces at facility used for the zinc 

production. 

Deleted: kiln or 

Deleted: kiln or
289

(c) If GHG emissions from a Waelz kiln or 

electrothermic furnace are vented through the same stack as 

any combustion unit or process equipment that reports CO2

emissions using a CEMS that complies with the Tier 4 

Calculation Methodology in subpart C of this part (General 

Stationary Fuel Combustion Sources), then the calculation 

methodology in paragraph (b) of this section shall not be 

used to calculate process emissions. The owner or operator 

shall report under this subpart the combined stack 

emissions according to the Tier 4 Calculation Methodology 

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

in subpart C of this part. 

§98.334 Monitoring and QA/QC requirements.

If you determine CO2 emissions using the carbon input 

procedure in §98.333(b)(1)and (b)(2), you must meet the 

requirements specified in paragraphs (a) and (b) of this 

section. 

(a) Determine the mass of each solid carboncontaining input material consumed using facility 

instruments, procedures, or records used for accounting 

purposes including direct measurement weighing or through 

the use of purchase records same plant instruments or 

procedures that are used for accounting purposes (such as 

weigh hoppers, belt weigh feeders, weighed purchased 
290

quantities in shipments or containers, combination of bulk 

density and volume measurements, etc.). Record the total 

mass for the materials consumed each calendar month and sum 

the monthly mass to determine the annual mass for each 

input material. 

(b) For each input material identified in paragraph 

(a) of this section, you must determine the average carbon 

content of the material consumed or used in the calendar 

year using the methods specified in either paragraph (b)(1) 

or (b)(2) of this section. 

(1) Information provided by your material supplier. 

(2) Collecting and analyzing at least three 

representative samples of the material using the 

appropriate testing method. For each carbon-containing 

input material identified for which the carbon content is 

not provided by your material supplier, the carbon content 

of the material must be analyzed at least annually using 

the appropriate standard methods (and their QA/QC 

procedures), which are identified in paragraphs (b)(2)(i) 

through (b)(2)(iii) of this section, as applicable. If you 

document that a specific process input or output 

contributes less than one percent of the total mass of 

carbon into or out of the process, you do not have to 
291

determine the monthly mass or annual carbon content of that 

input or output. 

(i) Using ASTM E1941-04 Standard Test Method for 

Determination of Carbon in Refractory and Reactive Metals 

and Their Alloys (incorporated by reference, see §98.7), 

analyze zinc bearing materials. 

(ii) Using ASTM D5373-08 Standard Test Methods for 

Instrumental Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal (incorporated by 

reference, see §98.7), analyze carbonaceous reducing agents 

and carbon electrodes. 

(iii) Using ASTM C25-06 Standard Test Methods for 

Chemical Analysis of Limestone, Quicklime, and Hydrated 

Lime (incorporated by reference, see §98.7), analyze flux 

materials such as limestone or dolomite. 

§98.335 Procedures for estimating missing data.

For the carbon input procedure in §98.333(b), a 

complete record of all measured parameters used in the GHG 

emissions calculations is required (e.g., raw materials 

carbon content values, etc.). Therefore, whenever a 

quality-assured value of a required parameter is 

unavailable, a substitute data value for the missing 

parameter shall be used in the calculations as specified in 

paragraphs (a) and (b) of this section. You must document 
292

and keep records of the procedures used for all such 

estimates. 

(a) For missing records of the carbon content of 

inputs for facilities that estimate emissions using the 

carbon input procedure in §98.333(b); 100 percent data 

availability is required. You must repeat the test for 

average carbon contents of inputs according to the 

procedures in §98.335(b) if data are missing. 

(b) For missing records of the annual mass of carboncontaining inputs using the carbon input procedure in 

§98.333(b), the substitute data value must be based on the 

best available estimate of the mass of the input material 

from all available process data or information used for 

accounting purposes, such as purchase records. 

§98.336 Data reporting requirements.

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

each annual report must contain the information specified 

in paragraphs (a) or (b) of this section, as applicable, 

for each Waelz kiln or electrothermic furnace. 

(a) If a CEMS is used to measure CO2 emissions, then 

you must report under this subpart the relevant information 

required for the Tier 4 Calculation Methodology in §98.36

and the information listed in this paragraph (a): 

(1) Annual zinc product production capacity (tons). 

Deleted: 7
293

(2) Annual production quantity for each zinc product 

(tons). 

(3) Annual facility production quantity for each zinc 

product (tons). 

(4) Number of Waelz kilns at each facility used for 

zinc production. 

(5) Number of electrothermic furnaces at each 

facility used for zinc production. 

(b) If a CEMS is not used to measure CO2 emissions, 

then you must report the information listed in this 

paragraph (b): 

(1) Identification number and annual process CO2

emissions from each individual Waelz kiln or electrothermic 

furnace (metric tons). 

(2) Annual zinc product production capacity (tons). 

(3) Annual production quantity for each zinc product 

(tons). 

(4) Number of Waelz kilns at each facility used for 

zinc production. 

(5) Number of electrothermic furnaces at each 

facility used for zinc production. 

(6) Annual mass of each carbon-containing input 

material charged to each kiln or furnace (including zinc 

bearing material, flux materials (e.g., limestone, 

Deleted: Kiln i
294

dolomite), carbon electrode, and other carbonaceous 

materials (e.g., coal, coke)) (tons). 

(7) Carbon content of each carbon-containing input 

material charged to each kiln or furnace (including zinc 

bearing material, flux materials, and other carbonaceous 

materials) from the annual carbon analysis or from 

information provided by the material supplier for each kiln 

or furnace (percent by weight, expressed as a decimal 

fraction). 

(8) Whether carbon content of each carbon-containing 

input material charged to each kiln or furnace is based on 

reports from the supplier or through self measurement using 

applicable ASTM standard method. 

(9) If carbon content of each carbon-containing input 

material charged to each kiln or furnace is based on self 

measurement, the ASTM Standard Test Method used. 

(10) Carbon content of the carbon electrode used in 

each furnace from the annual carbon analysis or from 

information provided by the material supplier (percent by 

weight, expressed as a decimal fraction). 

(11) Whether carbon content of the carbon electrode 

used in each furnace is based on reports from the supplier 

or through self measurement using applicable ASTM standard 

method. 
295

(12) If carbon content of carbon electrode used in 

each furnace is based on self measurement, the ASTM 

standard method used. 

(13) If you use the missing data procedures in 

§98.335(b), you must report how the monthly mass of carboncontaining materials with missing data was determined and 

the number of months the missing data procedures were used. 

§98.337 Records that must be retained.

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

must retain the records specified in paragraphs (a) through 

(b) of this section for each zinc production facility. 

(a) If a CEMS is used to measure emissions, then you 

must retain under this subpart the records required for the 

Tier 4 Calculation Methodology in §98.37 and the 

information listed in this paragraph (a): 

(1) Monthly facility production quantity for each 

zinc product (tons). 

(2) Annual operating hours for all Waelz kilns and 

electrothermic furnaces used in zinc production. 

(b) If a CEMS is not used to measure emissions, you 

must also retain the records specified in paragraphs (b)(1) 

through (b)(7) of this section. 

(1) Records of all analyses and calculations 

conducted for data reported as listed in §98.336(b). 
296

(2) Annual operating hours for Waelz kilns and 

electrothermic furnaces used in zinc production. 

(3) Monthly production quantity for each zinc product 

(tons). 

(4) Monthly mass of zinc bearing materials, flux 

materials (e.g., limestone, dolomite), and carbonaceous 

materials (e.g., coal, coke) charged to the kiln or furnace 

(tons). 

(5) Sampling and analysis records for carbon content 

of zinc bearing materials, flux materials (e.g., limestone, 

dolomite), carbonaceous materials (e.g., coal, coke), 

charged to the kiln or furnace (percent by weight, 

expressed as a decimal fraction). 

(6) Monthly mass of carbon electrode consumed in for 

each electrothermic furnace (tons). 

(7) Sampling and analysis records for carbon content 

of electrode materials. 

(8) You must keep records that include a detailed 

explanation of how company records of measurements are used 

to estimate the carbon input to each Waelz kiln or 

electrothermic furnace, as applicable to your facility, 

including documentation of any materials excluded from 

Equation GG-1 of this subpart that contribute less than 

1 percent of the total carbon inputs to the process. You 
297

also must document the procedures used to ensure the 

accuracy of the measurements of materials fed, charged, or 

placed in an affected unit including, but not limited to, 

calibration of weighing equipment and other measurement 

devices. The estimated accuracy of measurements made with 

these devices must also be recorded, and the technical 

basis for these estimates must be provided. 

§98.338 Definitions.

All terms used in this subpart have the same meaning 

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

Subpart HH—Municipal Solid Waste Landfills 

§98.340 Definition of the source category.

(a) This source category applies to municipal solid 

waste (MSW) landfills that accepted waste on or after 

January 1, 1980. 

(b) This source category does not include Resource 

Conservation and Recovery Act (RCRA) Subtitle C or Toxic 

Substances Control Act (TSCA) hazardous waste landfills, 

dedicated construction and demolition waste landfills, or 

industrial waste landfills. 

(c) This source category consists of the following 

sources at municipal solid waste (MSW) landfills: 

landfills, landfill gas collection systems, and landfill 

gas destruction devices (including flares). 
298

§98.341 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a MSW landfill and the facility 

meets the requirements of §98.2(a)(1). 

§98.342 GHGs to report.

(a) You must report CH4 generation and CH4 emissions 

from landfills. 

(b) You must report CH4 destruction resulting from 

landfill gas collection and combustion systems. 

(c) You must report under subpart C of this part 

(General Stationary Fuel Combustion Sources) the emissions 

of CO2, CH4, and N2O from each stationary combustion unit 

following the requirements of subpart C. 

§98.343 Calculating GHG emissions.

(a) For all landfills subject to the reporting 

requirements of this subpart, calculate annual modeled CH4

generation according to the applicable requirements in 

paragraphs (a)(1) through (a)(3) of this section. 

(1) Calculate annual modeled CH4 generation using 

Equation HH-1 of this section. 

∑ ( )

−

=

− − − − −













= × × × × × × −

1

( 1) ( )

4

12

16 T

x S

k T x k T x

CH x F G W MCF DOC DOC F e e (Eq. HH-1) 

Where: 

GCH4 = Modeled methane generation rate in reporting 

year T (metric tons CH4). 
299

x = Year in which waste was disposed. 

S = Start year of calculation. Use the year 1960 

or the opening year of the landfill, whichever 

is more recent. 

T = Reporting year for which emissions are 

calculated. 

Wx = Quantity of waste disposed in the landfill in 

year x from measurement data, tipping fee 

receipts, or other company records (metric 

tons, as received (wet weight)). 

MCF = Methane correction factor (fraction). Use the

default value of 1. 

DOC = Degradable organic carbon from Table HH-1 of 

this subpart or measurement data, if available 

[fraction (metric tons C/metric ton waste)]. 

DOCF = Fraction of DOC dissimilated (fraction). Use 

the default value of 0.5. 

F = Fraction by volume of CH4 in landfill gas from 

measurement data on a dry basis, if available 

(fraction); default is 0.5. 

k = Rate constant from Table HH-1 of this subpart 

(yr-1). Select the most applicable k value for 

the majority of the past 10 years (or 

operating life, whichever is shorter).

(2) For years when material-specific waste quantity 

data are available, apply Equation HH-1 of this section for 

each waste quantity type and sum the CH4 generation rates 

for all waste types to calculate the total modeled CH4

generation rate for the landfill. Use the appropriate 

parameter values for k, DOC, MCF, DOCF, and F shown in Table 

HH-1 of this subpart. The annual quantity of each type of 

waste disposed must be calculated as the sum of the daily 

quantities of waste (of that type) disposed. You may use 

the bulk waste parameters for a portion of your waste 

Deleted: X

Deleted: 50 years prior to 

the year of the emissions 

estimate, 

Deleted: X

Deleted: L0 = CH4 generation 

potential (metric tons 

CH4/metric ton waste) = 

MCF×DOC×DOCF×F×16/12. ¶

Deleted: ;

Deleted: is

Deleted: ;

Deleted: is

Deleted: or measurement data, 

if available 
300

materials when using the material-specific modeling 

approach for mixed waste streams that cannot be designated 

to a specific material type. For years when waste 

composition data are not available, use the bulk waste 

parameter values for k and DOC in Table HH-1 of this 

subpart for the total quantity of waste disposed in those 

years. 

(3) Beginning in the first emissions monitoring year 

(2010 or later) and for each year thereafter, if scales are 

in place, you must determine the annual quantity of waste 

(in metric tons as received, i.e., wet weight) disposed of 

in the landfill using paragraph (a)(3)(i) of this section 

for all containers and for all vehicles, other than 

passenger cars or light duty pickup trucks, used to haul 

waste to the landfill. If scales are not in place, you 

must use paragraph (a)(3)(ii) of this section to determine 

the annual quantity of waste disposed. For waste hauled to 

the landfill in passenger cars or light duty pickup trucks, 

you may use either pargraph (a)(3)(i) or paragraph 

(a)(3)(ii) of this section to determine the annual quantity 

of waste disposed. The approach used to determine the 

annual quantity of waste disposed of must be documented in 

the monitoring plan. 

Deleted: L0

Deleted: 
301

(i) Use direct mass measurements of each individual 

load received at the landfill using either of the following 

methods: 

(A) Weigh using mass scales each vehicle or container 

used to haul waste as it enters the landfill or disposal 

area; weigh using mass scales each vehicle or container 

after it has off-loaded the waste; determine the quantity 

of waste received from the individual load as the 

difference in the two mass measurements; and determine the 

annual quantity of waste received as the sum of all waste 

loads received during the year. Alternatively, you may 

determine annual quantity of waste by summing the weights 

of all vehicles and containers entering the landfill and 

subtracting from it the sum of all the weights of vehicles 

and containers after they have off-loaded the waste in the 

landfill.

(B) Weigh using mass scales each vehicle or container 

used to haul waste as it enters the landfill or disposal 

area; determine a representative tare weight by vehicle or 

container type by weighing no less than 5 of each type of 

vehicle or container after it has off-loaded the waste; 

determine the quantity of waste received from the 

individual load as the difference between the measured 

weight in and the tare weight determined for that 
302

container/vehicle type; and determine the annual quantity 

of waste received as the sum of all waste loads received 

during the year.

(ii) Determine the working capacity in units of mass 

for each type of container or vehicle used to haul waste to 

the landfill (e.g., using volumetric capacity and waste 

density measurements; direct measurement of a selected 

number of passenger vehicles and light duty pick-up trucks; 

or similar methods); record the number of loads received at 

the landfill by vehicle/container type; calculate the 

annual mass per vehicle/container type as the mass product 

of the number of loads of that vehicle/container multiplied 

by its working capacity; and calculate the annual quantity 

of waste received as the sum of the annual mass per 

vehicle/container type across all of the vehicle/container 

types used to haul waste to the landfill. 

(4) For years prior to the first emissions monitoring 

year, use methods in paragraph (a)(3) of this section when 

waste disposal quantity data are readily available. When

waste disposal quantity data are not readily available, Wx

shall be estimated using one of the applicable methods in 

paragraphs (a)(4)(i) through (a)(4)(iii) of this section. 

You must determine which method is most applicable to the 

conditions and disposal history of your facility. 

Deleted: 3

Deleted: reporting for which

Deleted: ies

Deleted: 3

Deleted: 3
303

Historical waste disposal quantities should only be 

determined once, as part of the first annual report, and 

the same values should be used for all subsequent annual 

reports, supplemented by the next year’s data on new waste 

disposal. 

(i) Assume all prior years waste disposal quantities 

are the same as the waste quantity in the first year for 

which waste quantities are available. 

(ii) Use the estimated population served by the 

landfill in each year, the values for national average per 

capita waste generation, and fraction of generated waste 

disposed of in solid waste disposal sites found in Table 

HH-2 of this subpart, and calculate the waste quantity 

landfilled using Equation HH-2 of this section. 

Wx = POPx ×WDRx (Eq. HH-2) 

Where: 

Wx = Quantity of waste placed in the landfill in year 

x (metric tons, wet basis). 

POPx = Population served by the landfill in year x from 

city population, census data, or other estimates 

(capita). 

WDRx = Average per capita waste disposal rate for year x 

from Table HH-2 of this subpart (metric tons per 

capita per year, wet basis; tons/cap/yr). 

(iii) Use a constant average waste disposal quantity 

calculated using Equation HH-3 of this section for each 

year the landfill was in operation (i.e., from the first 

Deleted: and use that method 

to estimate waste disposal 

quantities

Deleted: 

Deleted: reporting 

Deleted: of 

Deleted: G

Deleted: generation 

Deleted: %SWDS = Percent of 

waste generated subsequently 

managed in solid waste 

disposal sites (i.e., 

landfills) for year x from 

Table HH-2 of this subpart.¶
304

year accepting waste until the last year for which waste 

disposal data is unavailable, inclusive). 

( − +1)

=

YrData YrOpen

LFC Wx (Eq. HH-3) 

Where: 

Wx = Quantity of waste placed in the landfill in year 

x (metric tons, wet basis). 

LFC = Landfill capacity or, for operating landfills, 

capacity of the landfill used (or the total 

quantity of waste-in-place) at the end of the 

year prior to the year when waste disposal data 

are available from design drawings or 

engineering estimates (metric tons). 

YrData = Year in which the landfill last received waste 

or, for operating landfills, the year prior to 

the first reporting year when waste disposal 

data is first available from company records, or 

best available data. 

YrOpen = Year in which the landfill first received waste 

from company records or best available data. If 

no data are available for estimating YrOpen for 

a closed landfill, use 30 years as the default 

operating life of the landfill. 

(b) For landfills with gas collection systems, 

calculate the quantity of CH4 destroyed according to the 

requirements in paragraphs (b)(1) and (b)(2) of this 

section. 

(1) If you continuously monitor the flow rate, CH4

concentration, temperature, pressure, and, if necessary,

moisture content of the landfill gas that is collected and 

routed to a destruction device (before any treatment 

equipment) using a monitoring meter specifically for CH4

Deleted: AR

Deleted: Annual average waste 

acceptance rate (metric tons 

per year)

Deleted: currently 
305

gas, as specified in §98.344, you must use this monitoring 

system and calculate the quantity of CH4 recovered for 

destruction using Equation HH-4 of this section. A fully 

integrated system that directly reports CH4 content requires 

no other calculation than summing the results of all 

monitoring periods for a given year. 

( ) ( )

( )

( )

( )

1,000

0.454

1atm

P

T

520 R

0.0423

100%

C

R V

N

n 1

n

n

n ∑ n

=

















× ×

°

= × × × × K MC n

(Eq. HH-4) 

Where: 

R = Annual quantity of recovered CH4 (metric 

tons CH4). 

N = Total number of measurement periods in a 

year. Use daily averaging periods for 

continuous monitoring system and N=365 (or 

N=366 for leap years). For weekly 

sampling, as provided in paragraph (b)(2) 

of this section, use N=52. 

n = Index for measurement period. 

(V)n = Cumulative volumetric flow for the 

measurement period in actual cubic feet 

(acf). If the flow rate meter 

automatically corrects for temperature and 

pressure, replace “520°R/(T)n × (P)n/1 atm” 

with “1”. 

(KMC)n = Moisture correction term for the 

measurement period, volumetric basis, as 

follows: (KMC)n= 1 when (V)n and (C)n are 

both measured on a dry basis or if both are 

measured on a wet basis; (KMC)n = [1-(fH2O)n] 

when (V)n is measured on a wet basis and 

(C)n is measured on a dry basis; and (KMC)n = 

1/[1-(fH2O)n] when (V)n is measured on a dry 

basis and (C)n is measured on a wet basis.

(fH2O)n = Average moisture content of landfill gas 

during the measurement period, volumetric 

Deleted: (

Deleted: )

Deleted: Daily average

Deleted: rate 

Deleted: day n 

Deleted: m

Deleted: If the CH4

concentration is determined 

on a dry basis and the flow 

rate meter automatically 

corrects for moisture 

content, replace the term 

[1-(fH20)n] with 1.

Deleted: (fH2O)n

Deleted: Daily average m

Deleted: content
306

basis (cubic feet water per cubic feet 

landfill gas) (CCH4)n = Average CH4

concentration of landfill gas for the 

measurement period (volume %). 

0.0423 = Density of CH4 lb/cf at 520°R or 60°F and 1 

atm. 

(T)n = Temperature at which flow is measured for 

the measurement period (°R). 

(P)n = Pressure at which flow is measured for the 

measurement period (atm). 

0.454/1,000 = Conversion factor (metric ton/lb). 

(2) If you do not continuously monitor according to 

paragraph (b)(1) of this section, you must determine the 

flow rate, CH4 concentration, temperature, pressure, and 

moisture content of the landfill gas that is collected and 

routed to a destruction device (before any treatment 

equipment) according to the requirements in paragraphs 

(b)(2)(i) through (b)(2)(iii) of this section and calculate 

the quantity of CH4 recovered for destruction using Equation 

HH-4 of this section. 

(i) Continuously monitor gas flow rate and determine 

the cumulative volume of landfill gas each week and the 

cumulative volume of landfill gas each year that is 

collected and routed to a destruction device (before any 

treatment equipment). Under this option, the gas flow 

meter is not required to automatically correct for 

temperature, pressure, or, if necessary, moisture content. 

If the gas flow meter is not equipped with automatic 

Deleted: of landfill gas, 

volumetric basis (cubic feet 

water per cubic feet 

landfill gas). ¶

Deleted: Daily a

Deleted: day n

Deleted: , dry basis

Deleted: If the CH4

concentration is determined 

on a wet basis, replace the 

term [1-(fH20)n] with 1. 

Deleted: day n

Deleted: day 

Deleted: n

Deleted: 1,440 = Conversion 

factor (min/day). ¶

Deleted: at least weekly 
307

correction for temperature, pressure, or, if necessary, 

moisture content, you must determine these parameters as 

specified in paragraph (b)(2)(iii) of this section. 

(ii) Determine the CH4 concentration in the landfill 

gas that is collected and routed to a destruction device 

(before any treatment equipment) in a location near or 

representative of the location of the gas flow meter once 

each calendar week, with at least three days between 

measurements. 

(iii) If the gas flow meter is not equipped with 

automatic correction for temperature, pressure, or, if 

necessary, moisture content: 

(A) Determine the temperature and pressure in the 

landfill gas that is collected and routed to a destruction 

device (before any treatment equipment) in a location near 

or representative of the location of the gas flow meter

once each calendar week, with at least three days between 

measurements. 

(B) If the CH4 concentration is determined on a dry 

basis and flow is determined on a wet basis or CH4

concentration is determined on a wet basis and flow is 

determined on a dry basis, and the flow meter does not 

automatically correct for moisture content, determine the 

moisture content in the landfill gas that is collected and 

Deleted: no less than weekly

Deleted: ,

Deleted: no less than weekly
308

routed to a destruction device (before any treatment 

equipment) in a location near or representative of the 

location of the gas flow meter once each calendar week, 

with at least three days between measurements.

(c) For all landfills, calculate CH4 generation 

(adjusted for oxidation in cover materials) and actual CH4

emissions (taking into account any CH4 recovery, and 

oxidation in cover materials) according to the applicable 

methods in paragraphs (c)(1) through (c)(3) of this 

section. 

(1) Calculate CH4 generation, adjusted for oxidation, 

from the modeled CH4 (GCH4 from Equation HH-1 of this 

section) using Equation HH-5 of this section.

MG G (1- OX) = CH4 × (Eq. HH-5) 

Where: 

MG = Methane generation, adjusted for oxidation, from the 

landfill in the reporting year (metric tons CH4). 

GCH4 = Modeled methane generation rate in reporting year 

from Equation HH-1 of this section (metric tons 

CH4). 

OX = Oxidation fraction. Use the default value of 0.1 

(10%). 

(2) For landfills that do not have landfill gas 

collection systems, the CH4 emissions are equal to the CH4

Deleted: no less than weekly

Deleted: C
309

generation (MG) calculated in Equation HH-5 of this 

section. 

(3) For landfills with landfill gas collection 

systems, calculate CH4 emissions using the methodologies 

specified in paragraphs (c)(3)(i) and (c)(3)(ii) of this 

section. 

(i) Calculate CH4 emissions from the modeled CH4

generation and measured CH4 recovery using Equation HH-6 of 

this section. 

[( ) ( ) ( ( ))] CH4 Dest Emissions = G -R × 1−OX +R× 1− DE× f (Eq. HH-6) 

Where: 

Emissions = Methane emissions from the landfill in the 

reporting year (metric tons CH4). 

GCH4 = Modeled methane generation rate in reporting 

year from Equation HH-1 of this section or the 

quantity of recovered CH4 from Equation HH-4 

of this section, whichever is greater (metric 

tons CH4). 

R = Quantity of recovered CH4 from Equation HH-4 

of this section (metric tons). 

OX = Oxidation fraction. Use the oxidation 

fraction default value of 0.1 (10%). 

DE = Destruction efficiency (lesser of 

manufacturer’s specified destruction 

efficiency and 0.99). If the gas is 

transported off-site for destruction, use 

DE = 1. 

fDest = Fraction of hours the destruction device was 

operating (annual operating hours/8760 hours 

per year). If the gas is destroyed in a backup flare (or simlar device) or if the gas is 

transported off-site for destruction, use 

fDest = 1. 
310

(ii) Calculate CH4 generation and CH4 emissions using 

measured CH4 recovery and estimated gas collection 

efficiency and Equations HH-7 and HH-8 of this section. 

(1- OX)

CE f

R MG

Rec

×

×

= (Eq. HH-7) 

( ) ( ( ))











× − + × − ×

















−

×

= Dest

Rec

R 1 OX R 1 DE f

CE f

R

Emissions (Eq. HH-8) 

Where: 

MG = Methane generation, adjusted for oxidation, 

from the landfill in the reporting year (metric 

tons CH4). 

Emissions = Methane emissions from the landfill in the 

reporting year (metric tons CH4). 

R = Quantity of recovered CH4 from Equation HH-4 of 

this section (metric tons CH4). 

CE = Collection efficiency estimated at landfill, 

taking into account system coverage, operation, 

and cover system materials from Table HH-3 of 

this subpart. If area by soil cover type 

information is not available, use default value 

of 0.75 (CE4 in table HH-3 of this subpart) for 

all areas under active influence of the 

collection system. 

fRec = Fraction of hours the recovery system was 

operating (annual operating hours/8760 hours 

per year). 

OX = Oxidation fraction. Use the oxidation 

fractions default value of 0.1 (10%). 

DE = Destruction efficiency, (lesser of 

manufacturer’s specified destruction efficiency 

and 0.99). If the gas is transported off-site 

for destruction, use DE = 1. 

fDest = Fraction of hours the destruction device was 

operating (device operating hours/8760 hours 

per year). If the gas is destroyed in a backup flare (or similar device) or if the gas is 

transported off-site for destruction, use 

fDest = 1. 

§98.344 Monitoring and QA/QC requirements. 
311

(a) Mass measurement equipment used to determine the 

quantity of waste landfilled on or after January 1, 2010 

must meet the requirements for weighing equipment as 

described in “Specifications, Tolerances, and Other 

Technical Requirements For Weighing and Measuring Devices” 

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

§98.7). 

(b) For landfills with gas collection systems, 

operate, maintain, and calibrate a gas composition monitor 

capable of measuring the concentration of CH4 in the 

recovered landfill gas using one of the methods specified 

in paragraphs (b)(1) through (b)(6) of this section or as 

specified by the manufacturer. Gas composition monitors 

shall be calibrated prior to the first reporting year and 

recalibrated either annually or at the minimum frequency 

specified by the manufacturer, whichever is more frequent, 

or whenever the error in the midrange calibration check 

exceeds +/- 10 percent. 

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

(2) ASTM D1945-03, Standard Test Method for Analysis 

of Natural Gas by Gas Chromatography (incorporated by 

reference, see §98.7). 

Deleted: T

Deleted: be determined using 

mass measurement equipment 

Deleted: ing

Deleted: commercial 

Deleted: install, 
312

(3) ASTM D1946-90 (Reapproved 2006), Standard 

Practice for Analysis of Reformed Gas by Gas Chromatography 

(incorporated by reference, see §98.7). 

(4) GPA Standard 2261-00, Analysis for Natural Gas 

and Similar Gaseous Mixtures by Gas Chromatography. 

(5) UOP539-97 Refinery Gas Analysis by Gas 

Chromatography (incorporated by reference, see §98.7). 

(6) As an alternative to the gas chromatography 

methods provided in paragraphs (b)(1) through (b)(5) of 

this section, you may use total gaseous organic 

concentration analyzers and calculate the methane 

concentration following the requirements in paragraphs 

(b)(6)(i) through (b)(6)(iii) of this section. 

(i) Use Method 25A or 25B at 40 CFR part 60, appendix 

A-7 to determine total gaseous organic concentration. You 

must calibrate the instrument with methane and determine 

the total gaseous organic concentration as carbon (or as 

methane; K=1 in Equation 25A-1 of Method 25A at 40 CFR part 

60, appendix A-7). 

(ii) Determine a non-methane organic carbon 

correction factor at the routine sampling location no less 

frequently than once a reporting year following the 

requirements in paragraphs (b)(6)(ii)(A) through 

(b)(6)(ii)(C) of this section. 
313

(A) Take a minimum of three grab samples of the 

landfill gas with a minimum of 20 minutes between samples 

and determine the methane composition of the landfill gas 

using one of the methods specified in paragraphs (b)(1) 

through (b)(5) of this section. 

(B) As soon as practical after each grab sample is 

collected and prior to the collection of a subsequent grab 

sample, determine the total gaseous organic concentration 

of the landfilll gas using either Method 25A or 25B at 40 

CFR part 60, appendix A-7 as specified in paragaph 

(b)(6)(i) of this section. 

(C) Determine the arithmetic average methane 

concentration and the arithmetic average total gaseous 

organic concentration of the samples analyzed according to 

paragraphs (b)(6)(ii)(A) and (b)(6)(ii)(B) of this section, 

respectively, and calculate the non-methane organic carbon 

correction factor as the ratio of the average methane 

concentration to the average total gaseous organic 

concentration. If the ratio exceeds 1, use 1 for the nonmethane organic carbon correction factor. 

(iii) Calculate the methane concentration as 

specified in Equation HH-9 of this section. 

NMOC CTGOC CCH4 = f × (Eq. HH-9) 

Where: 

Deleted: that is collected 

and routed to a destruction 

device (before any treatment 

equipment) 

Deleted: specificed 

Deleted: that is collected 

and routed to a destruction 

device (before any treatment 

equipment) 
314

CCH4 = Methane concentration in the landfill gas 

(volume %) for use in Equation HH-4. 

fNMOC = Non-methane organic carbon correction factor 

from the most recent determination of the nonmethane organic carbon correction factor as 

specified in paragraph (b)(6)(ii) of this 

section (unitless). 

CTGOC = Total gaseous organic carbon concentration 

measured using Method 25A or 25B at 40 CFR 

part 60, appendix A-7 during routine 

monitoring of the landfill gas (volume %). 

(c) For landfills with gas collection systems, 

install, operate, maintain, and calibrate a gas flow meter 

capable of measuring the volumetric flow rate of the 

recovered landfill gas using one of the methods specified 

in paragraphs (c)(1) through (c)(8) of this section or as 

specified by the manufacturer. Each gas flow meter shall 

be recalibrated either biennially (every 2 years) or at the 

minimum frequency specified by the manufacturer. Except as 

provided in §98.343(b)(2)(i), each gas flow meter must be 

capable of correcting for the temperature and pressure and, 

if necessary, moisture content. 

(1) ASME MFC-3M-2004, Measurement of Fluid Flow in 

Pipes Using Orifice, Nozzle, and Venturi (incorporated by 

reference, see §98.7). 

Deleted: calibrated prior to 

the first year of reporting 

and 

Deleted: the gas composition 

monitor determines CH4

concentration on a dry basis
315

(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement 

of Gas Flow by Turbine Meters (incorporated by reference, 

see §98.7). 

(3) ASME MFC-6M-1998, Measurement of Fluid Flow in 

Pipes Using Vortex Flowmeters (incorporated by reference, 

see §98.7). 

(4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement 

of Gas Flow by Means of Critical Flow Venturi Nozzles 

(incorporated by reference, see §98.7). 

(5) ASME MFC-11M-2006 Measurement of Fluid Flow by 

Means of Coriolis Mass Flowmeters (incorporated by 

reference, see §98.7). The mass flow must be corrected to 

volumetric flow based on the measured temperature, 

pressure, and gas composition. 

(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using 

Small Bore Precision Orifice Meters (incorporated by 

reference, see §98.7). 

(7) ASME MFC-18M-2001 Measurement of Fluid Flow using 

Variable Area Meters (incorporated by reference, see 

§98.7). 

(8) Method 2A or 2D at 40 CFR part 60, appendix A-1. 

(d) All temperature, pressure, and if necessary, 

moisture content monitors must be calibrated using the 

procedures and frequencies specified by the manufacturer. 

Deleted: and 
316

(e) The owner or operator shall document the 

procedures used to ensure the accuracy of the estimates of 

disposal quantities and, if applicable, gas flow rate, gas 

composition, temperature, pressure, and moisture content

measurements. These procedures include, but are not 

limited to, calibration of weighing equipment, fuel flow 

meters, and other measurement devices. The estimated 

accuracy of measurements made with these devices shall also 

be recorded, and the technical basis for these estimates 

shall be provided. 

§98.345 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable (e.g., if a meter 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, according to the requirements in 

paragraphs (a) through (c) of this section. 

(a) For each missing value of the CH4 content, the 

substitute data value shall be the arithmetic average of 

the quality-assured values of that parameter immediately 

preceding and immediately following the missing data 

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

Deleted: and 
317

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

the missing data substitution. If, for a particular 

parameter, no quality-assured data are available prior to 

the missing data incident, the substitute data value shall 

be the first quality-assured value obtained after the 

missing data period. 

(b) For missing gas flow rates, the substitute data 

value shall be the arithmetic average of the qualityassured values of that parameter immediately preceding and 

immediately following the missing data incident. If the 

“after” value is not obtained by the end of the reporting 

year, you may use the “before” value for the missing data 

substitution. If, for a particular parameter, no qualityassured data are available prior to the missing data 

incident, the substitute data value shall be the first 

quality-assured value obtained after the missing data 

period. 

(c) For missing daily waste disposal quantity data 

for disposal in reporting years, the substitute value shall 

be the average daily waste disposal quantity for that day 

of the week as measured on the week before and week after 

the missing daily data. 

§98.346 Data reporting requirements. 
318

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

each annual report must contain the following information 

for each landfill. 

(a) A classification of the landfill as “open” 

(actively received waste in the reporting year) or “closed” 

(no longer receiving waste), the year in which the landfill 

first started accepting waste for disposal, the last year 

the landfill accepted waste (for open landfills, enter the 

estimated year of landfill closure), the capacity (in 

metric tons) of the landfill, an indication of whether 

leachate recirculation is used during the reporting year 

and its typical frequency of use over the past 10 years 

(e.g., used several times a year for the past 10 years, 

used at least once a year for the past 10 years, used 

occasionally but not every year over the past 10 years, not 

used), an indication as to whether scales are present at 

the landfill, and the waste disposal quantity for each year 

of landfilling required to be included when using Equation 

HH-1 of this subpart (in metric tons, wet weight). 

(b) Method for estimating reporting year and 

historical waste disposal quantities, reason for its 

selection, and the range of years it is applied. For years 

when waste quantity data are determined using the methods 

in §98.343(a)(3), report separately the quantity of waste 

Deleted: y

Deleted: and 
319

determined using the methods in §98.343(a)(3)(i) and the 

quantity of waste determined using the methods in 

§98.343(a)(3)(ii). For historical waste disposal 

quantities that were not determined using the methods in 

§98.343(a)(3), provide the population served by the 

landfill for each year the Equation HH-2 of this subpart is 

applied, if applicable, or, for open landfills using 

Equation HH-3 of this subpart, provide the value of 

landfill capacity (LFC) used in the calculation. 

(c) Waste composition for each year of landfilling, 

if available, in percentage categorized as: 

(1) Municipal. 

(2) Biosolids or biological sludges. 

(3) Other, or more refined categories, such as those 

for which k rates are available in Table HH-1 of this 

subpart, and the method or basis for estimating waste 

composition. 

(d) For each waste type used to calculate CH4

generation using Equation HH-1 of this subpart, you must 

report: 

(1) Degradable organic carbon (DOC), methane 

correction factor (MCF), and fraction of DOC dissimilated 

(DOCF) values used in the calculations. 

(2) Decay rate (k) value used in the calculations. 
320

(e) Fraction of CH4 in landfill gas (F) and an 

indication of whether the fraction of CH4 was determined 

based on measured values or the default value. 

(f) The surface area of the landfill containing waste 

(in square meters), identification of the type of cover 

material used (as either organic cover, clay cover, sand 

cover, or other soil mixtures). If multiple cover types 

are used, the surface area associated with each cover type 

. 

(g) The modeled annual methane generation rate for 

the reporting year (metric tons CH4) calculated using 

Equation HH-1 of this subpart. 

(h) For landfills without gas collection systems, the 

annual methane emissions (i.e., the methane generation, 

adjusted for oxidation, calculated using Equation HH-5 of 

this subpart), reported in metric tons CH4, and an 

indication of whether passive vents and/or passive flares 

(vents or flares that are not considered part of the gas 

collection system as defined in §98.6) are present at this 

landfill. 

(i) For landfills with gas collection systems, you 

must report: 

Deleted: the

Deleted: types

Deleted: applicable to the 

landfill,

Deleted: and oxidation 

fraction for

Deleted: used to calculate 

the average oxidation 

fraction, and the average 

oxidation fraction used in 

the calculations

Deleted: 
321

(1) Total volumetric flow of landfill gas collected 

for destruction for the reporting year (cubic feet at 520°R 

or 60°F and 1 atm). 

(2) Annual average CH4 concentration of landfill gas 

collected for destruction (percent by volume). 

(3) Monthly average temperature and pressure for each 

month at which flow is measured for landfill gas collected 

for destruction, or statement that temperature and/or 

pressure is incorporated into internal calcuations run by 

the monitoring equipment. 

(4) An indication as to whether flow was measured on 

a wet or dry basis, an indication as to whether CH4

concntration was measured on a wet or dry basis, and if 

required for Equation HH-4, monthly average moisture 

content for each month at which flow is measured for 

landfill gas collected for destruction.(5) An indication 

of whether destruction occurs at the landfill facility or 

off-site. If destruction occurs at the landfill facility, 

also report an indication of whether a back-up destruction 

device is present at the landfill, the annual operating 

hours for the primary destruction device, the annual 

operating hours for the back-up destruction device (if 

present), and the destruction efficiency used (percent). 

Deleted: M

Deleted: pressure

Deleted: , or statement that 

temperature is incorporated 

into internal calcuations 

run by the monitoring 

equipment

Deleted: ¶

Deleted: operting 
322

(6) Annual quantity of recovered CH4 (metric tons CH4) 

calculated using Equation HH-4 of this subpart. 

(7) A description of the gas collection system 

(manufacturer, capacity, and number of wells), the surface 

area (square meters) and estimated waste depth (meters) for 

each area specified in Table HH-3 of this subpart, the 

estimated gas collection system efficiency for landfills 

with this gas collection system, the annual operating hours 

of the gas collection system, and an indication of whether 

passive vents and/or passive flares (vents or flares that 

are not considered part of the gas collection system as 

defined in §98.6) are present at the landfill. 

(8) Methane generation corrected for oxidation 

calculated using Equation HH-5 of this subpart, reported in 

metric tons CH4. 

(9) Methane generation (GCH4) value used as an input 

to Equation HH-6 of this subpart. Specify whether the 

value is modeled (GCH4 from HH-1 of this subpart or measured 

(R from Equation HH-4 of this subpart). 

(10) Methane generation corrected for oxidation 

calculated using Equation HH-7 of this subpart, reported in 

metric tons CH4. 

(11) Methane emissions calculated using Equation HH-6 

of this subpart, reported in metric tons CH4. 

Deleted: , etc.

Deleted: and 

Deleted: 

Deleted: 
323

(12) Methane emissions calculated using Equation HH-8 

of this subpart, reported in metric tons CH4. 

§98.347 Records that must be retained. 

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

you must retain the calibration records for all monitoring 

equipment, including the method or manufacturer’s 

specification used for calibration. You must retain 

records of all measurements made to determine tare weights 

and working capacities by vehicle/containter type if these 

are used to determine the annual waste quantities.

§98.348 Definitions.

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. 

Dedicated construction and demolition landfill means a 

landfill that only receives materials generated from the 

construction or destruction of structures such as 

buildings, roads, and bridges.

Destruction device means a flare, thermal oxidizer, 

boiler, turbine, internal combustion engine, or any other 

combustion unit used to destroy or oxidize methane 

contained in landfill gas.

Industrial waste landfill means any landfill other 

than a municipal solid waste landfill, a RCRA Subtitle C 

Deleted: A
324

hazardous waste landfill, or a TSCA hazardous waste 

landfill, in which industrial solid waste, such a RCRA 

Subtitle D wastes (nonhazardous industrial solid waste, 

defined in 40 CFR 257.2), commercial solid wastes, or 

conditionally exempt small quantity generator wastes, is 

placed. An industrial waste landfill includes all disposal 

areas at the facility.

Solid waste has the meaning established by the 

Administrator pursuant to the Solid Waste Disposal Act [42 

U.S.C.A. § 6901 et seq.]

Working capacity means the maximum volume or mass of 

waste that is actually placed in the landfill from an 

individual or representative type of container (such as a 

tank, truck, or roll-off bin) used to convey wastes to the 

landfill, taking into account that the container may not be 

able to be 100 perceont filled and/or 100 percent emptied 

for each load.

Table HH-1 of Subpart HH—Emissions Factors, Oxidation 

Factors and Methods 

Factor Default value Units 

Waste model-- bulk waste option 

k (precipitation plus 

recirculated leachatea

<20 inches/year) 

0.02 yr-1

k (precipitation plus 

recirculated leachatea

20-40 inches/year) 

0.038 yr-1

k (precipitation plus 

recirculated leachatea

0.057 yr-1

Deleted: and no leachate 

recirculation

Deleted: and no leachate 

recirculation
325

Factor Default value Units 

>40 inches/year) 

DOC (bulk waste) 0.20 Weight fraction, wet 

basis 

Waste model—All MSW landfills 

MCF 1 

DOCF 0.5 

F 0.5 

Waste model—MSW using waste composition option 

DOC (food waste) 0.15 Weight fraction, wet 

basis 

DOC (garden) 0.2 Weight fraction, wet 

basis 

DOC (paper) 0.4 Weight fraction, wet 

basis 

DOC (wood and straw) 0.43 Weight fraction, wet 

basis 

DOC (textiles) 0.24 Weight fraction, wet 

basis 

DOC (diapers) 0.24 Weight fraction, wet 

basis 

DOC (sewage sludge) 0.05 Weight fraction, wet 

basis 

DOC (inerts, e.g. 

glass, plastics, metal, 

cement)

0.00 Weight fraction, wet 

basis

DOC (bulk waste) 0.20 Weight fraction, wet 

basis 

k (food waste) 0.06 to 

0.185b

yr-1

k (garden) 0.05 to 0.10b yr-1

k (paper) 0.04 to 0.06b yr-1

k (wood and straw) 0.02 to 0.03b yr-1

k (textiles) 0.04 to 0.06b yr-1

k (diapers) 0.05 to 0.10b yr-1

k (sewage sludge) 0.06 to 

0.185b

yr-1

k (inerts e.g. glass, 

plastics, metal, 

cement)

0.00b yr-1

Calculating methane generation and emissions 

Deleted: or for landfill 

areas with leachate 

recirculation

Deleted: L0 (Equivalent to 

DOC = 0.2028 when MCF=1, 

DOCF=0.5, and F=0.5)

Deleted: a

Deleted: 10a

Deleted: 06a

Deleted: 03a

Deleted: 06a

Deleted: 10a

Deleted: 185a

... [1]
326

Factor Default value Units 

OX 0.1 

DE 0.99 

a Recirculated leachate (in inches/year) is the total volume of leachate 

recirculated divided by the area of the portion of the landfill 

containing waste with appropriate unit conversions.

b

Use the lesser value when the potential evapotranspiration rate 

exceeds the mean annual precipitation rate plus recirculated leachate. 

Use the greater value when the potential evapotranspiration rate does 

not exceed the mean annual precipitation rate plus recirculated

leachate. 

Table HH-2 of Subpart HH—U.S. Per Capita Waste Disposal 

Rates 

Year 

Waste per capita 

ton/cap/yr

1960 0.63 

1961 0.64 

1962 0.64 

1963 0.65 

1964 0.65 

1965 0.66 

1966 0.66 

1967 0.67 

1968 0.68 

1969 0.68 

1970 0.69 

1971 0.69 

1972 0.70 

1973 0.71 

1974 0.71 

1975 0.72 

1976 0.73 

1977 0.73 

1978 0.74 

1979 0.75 

1980 0.75 

1981 0.76 

1982 0.77 

1983 0.77 

1984 0.78 

1985 0.79 

1986 0.79 

1987 0.80 

1988 0.80 

1989 0.83

1990 0.82

Deleted: a

Deleted: and

Deleted: recirculation is 

not used

Deleted: or when

Deleted: recirculation is 

used

Deleted: 1950

Deleted: 85

Deleted: 4

... [2]
327

Year 

Waste per capita 

ton/cap/yr

1991 0.76

1992 0.74

1993 0.76

1994 0.75

1995 0.70

1996 0.68

1997 0.69

1998 0.75

1999 0.75

2000 0.80

2001 0.91

2002 1.02

2003 1.02

2004 1.01

2005 0.98

2006 0.95

2007 0.95

2008 0.95

2009 0.95

Table HH-3 of Subpart HH—Landfill Gas Collection 

Efficiencies 

Description Landfill Gas Collection 

Efficiency 

A1: Area with no waste in-place Not applicable; do not 

use this area in the 

calculation. 

A2: Area without active gas collection, 

regardless of cover type 

CE2: 0%. 

A3: Area with daily soil cover and 

active gas collection 

CE3: 60%. 

A4: Area with an intermediate soil 

cover, or a final sold cover not meeting 

the criteria for A5 below, and active 

gas collection 

CE4: 75%. 

A5: Area with a final soil cover of 3 

feet or thicker of clay and/or

geomembrane cover system and active gas 

collection 

CE5: 95%. 

Area weighted average collection 

efficiency for landfills 

CEave1 = (A2*CE2 + 

A3*CE3 + A4*CE4 + 

A5*CE5)/(A2+A3+A4+A5). 

Deleted: 1950

Deleted: 8

Deleted: 6

Deleted: 8

Deleted: 7

Deleted: 2

Deleted: 71

Deleted: 72

Deleted: 78

Deleted: 78

Deleted: 4

Deleted: 5

Deleted: 6

Deleted: 6

Deleted: 6

Deleted: 1.06

Deleted: 1.06

Deleted: H2: Average depth 

of waste in area A2

Deleted: H3: Average depth 

of waste in area A3

Deleted: H4: Average depth 

of waste in area A4

Deleted: H5: Average depth 

of waste in area A5

... [3]
328

Subpart LL—Suppliers of Coal-based Liquid Fuels 

§98.380 Definition of the source category.

This source category consists of producers, importers, 

and exporters of products listed in Table MM-1 of subpart 

MM that are coal-based (coal-to-liquid products). 

(a) A producer is the owner or operator of a coal-toliquids facility. A coal-to-liquids facility is any 

facility engaged in converting coal into liquid products 

using a process involving conversion of coal into gas and 

then into liquids (e.g., Fischer-Tropsch) or conversion of 

coal directly into liquids (i.e., direct liquefaction). 

(b) An importer or exporter shall have the same 

meaning given in §98.6. 

§98.381 Reporting threshold.

Any supplier of coal-to-liquid products who meets the 

requirements of §98.2(a)(4) must report GHG emissions. 

§98.382 GHGs to report. 

You must report the CO2 emissions that would result 

from the complete combustion or oxidation of fossil-fuel 

products (besides coal or crude oil) that you produce, use 

as feedstock, import, or export during the calendar year. 

Additionally, producers must report CO2 emissions that would 

result from the complete combustion or oxidation of any 

biomass co-processed with fossil fuel-based feedstocks. 
329

§98.383 Calculating GHG emissions.

You must follow the calculation methodologies of 

§98.393 as if they applied to the appropriate coal-toliquid product supplier (i.e., calculation methodologies 

for refiners apply to producers of coal-to-liquid products 

and calculation methodologies for importers and exporters 

of petroleum products apply to importers and exporters of 

coal-to-liquid products). 

(a) In calculation methodologies in §98.393 for 

petroleum products or petroleum-based products, suppliers 

of coal-to-liquid products shall also include coal-toliquid products. 

(b) In calculation methodologies in §98.393 for noncrude feedstocks or non-crude petroleum feedstocks, 

producers of coal-to-liquid products shall also include 

coal-to-liquid products that enter the facility to be 

further processed or otherwise used on site. 

(c) In calculation methodologies in §98.393 for 

petroleum feedstocks, suppliers of coal-to-liquid products 

shall also include coal and coal-to-liquid products that 

enter the facility to be further processed or otherwise 

used on site. 

§98.384 Monitoring and QA/QC requirements.
330

You must follow the monitoring and QA/QC requirements 

in §98.394 as if they applied to the appropriate coal-toliquid product supplier. Any monitoring and QA/QC 

requirement for petroleum products in §98.394 also applies 

to coal-to-liquid products. 

§98.385 Procedures for estimating missing data.

You must follow the procedures for estimating missing 

data in §98.395 as if they applied to the appropriate coalto-liquid product supplier. Any procedure for estimating 

missing data for petroleum products in §98.395 also applies 

to coal-to-liquid products. 

§98.386 Data reporting requirements. 

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

the following requirements apply: 

(a) Producers shall report the following information 

for each coal-to-liquid facility: 

(1) For each product listed in Table MM-1 of subpart 

MM of this part that enters the coal-to-liquid facility to 

be further processed or otherwise used on site, report the 

annual quantity in metric tons or barrels by each quantity 

measurement standard method or other industry standard 

practice used. For natural gas liquids, quantity shall 

reflect the individual components of the product. 
331

(2) For each product listed in Table MM-1 of subpart 

MM of this part that enters the coal-to-liquid facility to 

be further processed or otherwise used on site, report the 

total annual quantity in metric tons or barrels. For 

natural gas liquids, quantity shall reflect the individual 

components of the product. 

(3) For each feedstock reported in paragraph (a)(2) 

that was produced by blending a fossil fuel-based product 

with a biomass-based product, report the percent of the 

volume reported in paragraph (a)(2) of this section that is 

fossil fuel-based. 

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(1) of this section. 

(5) For each product (leaving the coal-to-liquid 

facility) listed in Table MM-1 of subpart MM of this part, 

report the annual quantity in metric tons or barrels by 

each quantity measurement standard method or other industry 

standard practice used. For natural gas liquids, quantity 

shall reflect the individual components of the product. 

Those products that enter the facility, but are not 

reported in (a)(1), shall not be reported under this 

paragraph.
332

(6) For each product (leaving the coal-to-liquid 

facility) listed in Table MM-1 of subpart MM of this part, 

report the total annual quantity in metric tons or barrels. 

For natural gas liquids, quantity shall reflect the 

individual components of the product. Those products that 

enter the facility, but are not reported in (a)(2), shall 

not be reported under this paragraph.

(7) For each product reported in paragraph (a)(6) of 

this section that was produced by blending a fossil fuelbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (a)(6) of this 

section that is fossil fuel-based. 

(8) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(5) of this section. 

(9) For every feedstock reported in paragraph (a)(2) 

of this section for which Calculation Methodology 2 of 

subpart MM of this part was used to determine an emissions 

factor, report: 

(i) The number of samples collected according to 

§98.394(c). 

(ii) The sampling standard method used. 

(iii) The carbon share test results in percent mass. 

(iv) The standard method used to test carbon share. 
333

(v) The calculated CO2 emissions factor. 

(10) For every non-solid feedstock reported in 

paragraph (a)(2) of this section for which Calculation 

Methodology 2 of subpart MM of this part was used to 

determine an emissions factor, report: 

(i) The density test results in metric tons per 

barrel. 

(ii) The standard method used to test density. 

(11) For every product reported in paragraph (a)(6) 

of this section for which Calculation Methodology 2 of this 

subpart was used to determine an emissions factor, report: 

(i) The number of samples collected according to 

§98.394(c). 

(ii) The sampling standard method used. 

(iii) The carbon share test results in percent mass. 

(iv) The standard method used to test carbon share. 

(v) The calculated CO2 emissions factor. 

(12) For every non-solid product reported in 

paragraph (a)(6) of this section for which Calculation 

Methodology 2 of subpart MM of this part was used to 

determine an emissions factor, report: 

(i) The density test results in metric tons per 

barrel. 

(ii) The standard method used to test density. 
334

(13) For each specific type of biomass that enters 

the coal-to-liquid facility to be co-processed with fossil 

fuel-based feedstock to produce a product reported in 

paragraph (a)(6) of this section, report the annual 

quantity in metric tons or barrels by each quantity 

measurement standard method or other industry standard 

practice used. 

(14) For each specific type of biomass that enters 

the coal-to-liquid facility to be co-processed with fossil 

fuel-based feedstock to produce a product reported in 

paragraph (a)(6) of this section, report the total annual 

quantity in metric tons or barrels. 

(15) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(3) of this section. 

(16) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

feedstock reported in paragraph (a)(2) of this section, 

calculated according to §98.393(b) or (h). 

(17) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

product (leaving the coal-to-liquid facility) reported in 

paragraph (a)(6) of this section, calculated according to 

§98.393(a) or (h). 
335

(18) Annual CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

type of biomass feedstock co-processed with fossil fuelbased feedstocks reported in paragraph (a)(3) of this 

section, calculated according to §98.393(c). 

(19) Annual CO2 emissions that would result from the 

complete combustion or oxidation of all products, 

calculated according to §98.393(d). 

(20) Annual quantity of bulk NGLs in metric tons or 

barrels received for processing during the reporting year. 

(b) In addition to the information required by 

§98.3(c), each importer shall report all of the following 

information at the corporate level: 

(1) For each product listed in Table MM-1 of subpart 

MM of this part, report the annual quantity in metric tons 

or barrels by each quantity measurement standard method or 

other industry standard practice used. For natural gas 

liquids, quantity shall reflect the individual components 

of the product. 

(2) For each product listed in Table MM-1 of subpart 

MM of this part, report the total annual quantity in metric 

tons or barrels. For natural gas liquids, quantity shall 

reflect the individual components of the product as listed 

in Table MM-1 of subpart MM of this part. 
336

(3) For each product reported in paragraph (b)(2) of 

this section that was produced by blending a fossil fuelbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (b)(2) of this 

section that is fossil fuel-based. 

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (b)(1) of this section. 

(5) For each product reported in paragraph (b)(2) of 

this section for which Calculation Methodology 2 of this 

subpart used was used to determine an emissions factor, 

report: 

(i) The number of samples collected according to 

§98.394(c) 

(ii) The sampling standard method used. 

(iii) The carbon share test results in percent mass. 

(iv) The standard method used to test carbon share. 

(v) The calculated CO2 emissions factor in metric 

tons. 

(6) For each non-solid product reported in paragraph 

(b)(2) of this section for which Calculation Methodology 2 

of this subpart was used to determine an emissions factor, 

report: 
337

(i) The density test results in metric tons ber 

barrel. 

(ii) The standard method used to test density. 

(7) The CO2 emissions in metric tons that would result 

from the complete combustion or oxidation of each imported 

product reported in paragraph (b)(2) of this section, 

calculated according to §98.393(a). 

(8) The total sum of CO2 emissions that would result 

from the complete combution or oxidatio of all imported 

products, calculated according to §98.393(e). 

(c) In addition to the information required by 

§98.3(c), each exporter shall report all of the following 

information at the corporate level: 

(1) For each product listed in Table MM-1 of subpart 

MM of this part, report the annual quantity in metric tons 

or barrels by each quantity measurement standard method or 

other industry standard practice used. For natural gas 

liquids, quantity shall reflect the individual components 

of the product. 

(2) For each product listed in table MM-1 of subpart 

MM of this part, report the total annual quantity in metric 

tons or barrels. For natural gas liquids, quantity shall 

reflect the individual components of the product. 
338

(3) For each product reported in paragraph (c)(2) of 

this section that was produced by blending a fossil fuelbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (c)(2) of this 

section that is fossil fuel-based. 

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (c)(1) of this section. 

(5) For each product reported in paragraph (c)(2) of 

this section for which Calculation Methodology 2 of this 

subpart was used to determine an emissions factor, report: 

(i) The number of samples collected according to 

§98.394(c). 

(ii) The sampling standard method used. 

(iii) The carbon share test results in percent mass. 

(iv) The standard method used to test carbon share. 

(v) The calculated CO2 emissions factor in metric 

tons. 

(6) For each non-solid product reported in paragraph 

(c)(2) of this section for which Calculation Methodology 2 

of this subpart used was used to determine an emissions 

factor, report: 

(i) The density test results in metric tons per 

barrel. 
339

(ii) The standard method used to test density. 

(7) The CO2 emissions in metric tons that would result 

from the complete combustion or oxidation of each exported 

product reported in paragraph (c)(2) of this section, 

calculated according to §98.393(a). 

(8) Total sum of CO2 emissions that would result from 

the complete combustion or oxidation of all exported 

products, calculated according to §98.393(e). 

§98.387 Records that must be retained.

You must retain records according to the requirements 

in §98.397 as if they applied to the appropriate coal-toliquid product supplier (e.g., retaining copies of all 

reports submitted to EPA under §98.386 and records to 

support information contained in those reports). Any 

records for petroleum products that are required to be 

retained in §98.397 are also required for coal-to-liquid 

products. 

§98.388 Definitions.

All terms used in this subpart have the same meaning 

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

Subpart MM—Suppliers of Petroleum Products 

§98.390 Definition of the source category.

This source category consists of petroleum refineries 

and importers and exporters of petroleum products and 
340

natural gas liquids as listed in Table MM-1 of this 

subpart. 

(a) A petroleum refinery for the purpose of this 

subpart is any facility engaged in producing petroleum 

products through the distillation of crude oil. 

(b) A refiner is the owner or operator of a petroleum 

refinery. 

(c) Importer has the same meaning given in §98.6 and 

includes any entity that imports petroleum products or 

natural gas liquids as listed in Table MM-1 of this 

subpart. Any blender or refiner of refined or semi-refined 

petroleum products shall be considered an importer if it 

otherwise satisfies the aforementioned definition. 

(d) Exporter has the same meaning given in §98.6 and 

includes any entity that exports petroleum products or 

natural gas liquids as listed in Table MM-1 of this 

subpart. Any blender or refiner of refined or semi-refined 

petroleum products shall be considered an exporter if it 

otherwise satisfies the aforementioned definition. 

§98.391 Reporting threshold.

Any supplier of petroleum products who meets the 

requirements of §98.2(a)(4) must report GHG emissions. 

§98.392 GHGs to report. 
341

Suppliers of petroleum products must report the CO2

emissions that would result from the complete combustion or 

oxidation of each petroleum product and natural gas liquid 

produced, used as feedstock, imported, or exported during 

the calendar year. Additionally, refiners must report CO2

emissions that would result from the complete combustion or 

oxidation of any biomass co-processed with petroleum 

feedstocks. 

§98.393 Calculating GHG emissions.

(a) Calculation for individual products produced, 

imported, or exported. 

(1) Except as provided in paragraphs (h) and (i) of 

this section, any refiner, importer, or exporter shall 

calculate CO2 emissions from each individual petroleum 

product and natural gas liquid using Equation MM-1 of this 

section. 

CO2i = Producti * EFi (Eq. MM-1) 

Where: 

CO2i = Annual CO2 emissions that would result from the 

complete combustion or oxidation of each 

petroleum product or natural gas liquid “i” 

(metric tons). 

Producti = Annual volume of product “i” produced, 

imported, or exported by the reporting party 

(barrels). For refiners, this volume only 

includes products ex refinery gate, and 

excludes products that entered the refinery but 

are not reported under §98.396(a)(1). For 

natural gas liquids, volumes shall reflect the 
342

individual components of the product as listed 

in Table MM-1 of this subpart. 

EFi = Product-specific CO2 emission factor (metric 

tons CO2 per barrel). 

(2) In the event that an individual petroleum product 

is produced as a solid rather than liquid any refiner, 

importer, or exporter shall calculate CO2 emissions using 

Equation MM-1 of this section, where: 

CO2i = Annual CO2 emissions that would result from the 

complete combustion or oxidation of each 

petroleum product “i” (metric tons). 

Producti = Annual mass of product “i” produced, imported, 

or exported by the reporting party (metric 

tons). For refiners, this mass only includes 

products ex refinery gate, and excludes 

products that entered the refinery but are not 

reported under §98.396(a)(1). 

EFi = Product-specific CO2 emission factor (metric 

tons CO2 per metric ton of product). 

(b) Calculation for individual products that enter a 

refinery as a non-crude feedstock. 

(1) Except as provided in paragraphs (h) and (i) of 

this section, any refiner shall calculate CO2 emissions from 

each non-crude feedstock using Equation MM-2 of this 

section. 

CO2j = Feedstockj * EFj (Eq. MM-2) 

Where: 

CO2j = Annual CO2 emissions that would result from 

the complete combustion or oxidation of each 

non-crude feedstock “j” (metric tons). 

Feedstockj = Annual volume of a petroleum product or 

natural gas liquid “j” that enters the 

refinery to be further refined or otherwise 
343

used on site (barrels). For natural gas 

liquids, volumes shall reflect the individual 

components of the product as listed in table 

MM-1 of this subpart. 

EFj = Feedstock-specific CO2 emission factor (metric 

tons CO2 per barrel). 

(2) In the event that a non-crude feedstock enters a 

refinery as a solid rather than liquid, the refiner shall 

calculate CO2 emissions using Equation MM-2 of this section, 

where: 

CO2j = Annual CO2 emissions that would result from 

the complete combustion or oxidation of each 

non-crude feedstock “j” (metric tons). 

Feedstockj = Annual mass of a petroleum product “j” that 

enters the refinery to be further refined or 

otherwise used on site (metric tons). 

EFj = Feedstock-specific CO2 emission factor (metric 

tons CO2 per metric ton of feedstock). 

(c) Calculation for biomass co-processed with 

petroleum feedstocks. 

(1) Refiners shall calculate CO2 emissions from each 

type of biomass that enters a refinery and is co-processed 

with petroleum feedstocks using Equation MM-3 of this 

section. 

CO2m = Biomassm * EFm (Eq. MM-3) 

Where: 

CO2m = Annual CO2 emissions that would result from 

the complete combustion or oxidation of each 

type of biomass “m” (metric tons). 

Biomassm = Annual volume of a specific type of biomass 

that enters the refinery and is co-processed 

with petroleum feedstocks to produce a 
344

petroleum product reported under paragraph (a) 

of this section (barrels). 

EFm = Biomass-specific CO2 emission factor (metric 

tons CO2 per barrel). 

(2) In the event that biomass enters a refinery as a 

solid rather than liquid and is co-processed with petroleum 

feedstocks, the refiner shall calculate CO2 emissions from 

each type of biomass using Equation MM-3 of this section. 

Where: 

CO2m = Annual CO2 emissions that would result from 

the complete combustion or oxidation of each 

type of biomass “m” (metric tons). 

Biomassm = Total annual mass of a specific type of 

biomass that enters the refinery to be coprocessed with petroleum feedstocks to produce 

a petroleum product reported under paragraph 

(a) of this section (metric tons). 

EFm = Biomass-specific CO2 emission factor (metric 

tons CO2 per metric ton of biomass). 

(d) Summary calculation for refinery products. 

Refiners shall calculate annual CO2 emissions from all 

products using Equation MM-4 of this section. 

CO2r = ∑ (CO2i) − ∑ (CO2j) − ∑ (CO2m ) (Eq. MM-4) 

Where: 

CO2r = Annual CO2 emissions that would result from the 

complete combustion or oxidation of all 

petroleum products and natural gas liquids (ex 

refinery gate) minus non-crude feedstocks and 

any biomass to be co-processed with petroleum 

feedstocks. 

CO2i = Annual CO2 emissions that would result from the 

complete combustion or oxidation of each 
345

petroleum product or natural gas liquid “i” 

(metric tons). 

CO2j = Annual CO2 emissions that would result from the 

complete combustion or oxidation of each noncrude feedstock “j” (metric tons). 

CO2m = Annual CO2 emissions that would result from the 

complete combustion or oxidation of each type of 

biomass “m” (metric tons). 

(e) Summary calculation for importer and exporter 

products. Importers and exporters shall calculate annual 

CO2 emissions from all petroleum products and natural gas 

liquids imported or exported, respectively, using Equations 

MM-1 and MM-5 of this section. 

CO2x = ∑ (CO2i) (Eq. MM-5) 

Where: 

CO2i = Annual CO2 emissions that would result from the 

complete combustion or oxidation of each 

petroleum product or natural gas liquid “i” 

(metric tons). 

CO2x = Annual CO2 emissions that would result from the 

complete combustion or oxidation of all petroleum 

products and natural gas liquids. 

(f) Emission factors for petroleum products and 

natural gas liquids. The emission factor (EFi,j) for each 

petroleum product and natural gas liquid shall be 

determined using either of the calculation methods 

described in paragraphs (f)(1) or (f)(2) of this section. 

The same calculation method must be used for the entire 

quantity of the product for the reporting year. For 
346

refiners, the quantity of a product that enters a refinery 

(i.e., a non-crude feedstock) is considered separate from 

the quantity of a product ex refinery gate. 

(1) Calculation Method 1. To determine the emission 

factor (i.e., EFi in Equation MM-1) for solid products,

multiply the default carbon share factor (i.e., percent 

carbon by mass) in column B of Table MM–1 of this subpart 

for the appropriate product by 44/12. For all other 

products, use the default CO2 emission factor listed in 

column C of Table MM-1 of this subpart for the appropriate 

product. 

(2) Calculation Method 2. 

(i) For solid products, develop emission factors 

according to Equation MM-6 of this section using a value of 

1 for density and direct measurements of carbon share 

according to methods set forth in §98.394(c). For all 

other products, develop emission factors according to 

Equation MM-6 of this section using direct measurements of 

density and carbon share according to methods set forth in 

§98.394(c). 

EFi,j = Density * Carbon Share * (44/12) (Eq. MM-6) 

Where: 

EFi,j = Emission factor of the petroleum product or 

natural gas liquid (metric tons CO2 per 

barrel or per metric ton of product). 

Deleted: F

Deleted: use the default 

carbon share factor (i.e., 

percent carbon by mass) in 

column B of Table MM-1 of 

this subpart for the 

appropriate product
347

Density = Density of the petroleum product or natural 

gas liquid (metric tons per barrel for nonsolid products, 1 for solid products). 

Carbon share = Percent of total mass that carbon 

represents in the petroleum product or 

natural gas liquid, expressed as a fraction 

(e.g., 75% would be expressed as 0.75 in 

the above equation). 

44/12 = Conversion factor for carbon to carbon 

dioxide. 

(ii) If you use a standard method that involves gas 

chromatography to determine the percent mass of each 

component in a product, calculate the product’s carbon 

share using Equation MM-7 of this section. 

Carbon Share = ∑(%Composition i...n * %Massi...n) (Eq. MM-7) 

Where:

Carbon Share = Percent of total mass that carbon 

represents in the petroleum product or 

natural gas liquid. 

%Composition i...n = Percent of total mass that each 

molecular component in the petroleum 

product or natural gas liquid 

represents as determined by the 

procedures in the selected standard 

method. 

%Massi...n = Percent of total mass that carbon 

represents in each molecular component 

of the petroleum product or natural gas 

liquid. 

(g) Emission factors for biomass co-processed with 

petroleum feedstocks. Refiners shall use the most 

appropriate default CO2 emission factor (EFm) for biomass in 
348

Table MM-2 of this subpart to calculate CO2 emissions in 

paragraph (c) of this section. 

(h) Special procedures for blended biomass-based 

fuels. In the event that some portion of a petroleum 

product is biomass-based and was not derived by coprocessing biomass and petroleum feedstocks together (i.e., 

the petroleum product was produced by blending a petroleumbased product with a biomass-based fuel), the reporting 

party shall calculate emissions for the petroleum product 

according to one of the methods in paragraphs (h)(1) 

through (h)(4) of this section, as appropriate. 

(1) A reporter using Calculation Methodology 1 to 

determine the emission factor of a petroleum product shall 

calculate the CO2 emissions associated with that product 

using Equation MM-8 of this section in place of Equation 

MM-1 of this section. 

CO2i = Producti * EFi * %Voli (Eq. MM-8) 

Where: 

CO2i = Annual CO2 emissions that would result from the 

complete combustion or oxidation of each 

petroleum product “i” (metric tons). 

Producti = Annual volume of each petroleum product “i” 

produced, imported, or exported by the 

reporting party (barrels). For refiners, this 

volume only includes products ex refinery gate. 

EFi = Petroleum product-specific CO2 emission factor 

(metric tons CO2 per barrel) from Table MM-1 of 

this subpart. 
349

%Voli = Percent volume of product “i” that is 

petroleum-based, not including any denaturant 

that may be present in any ethanol product, 

expressed as a fraction (e.g., 75% would be 

expressed as 0.75 in the above equation). 

(2) A refinery using Calculation Methodology 1 of 

this subpart to determine the emission factor of a noncrude petroleum feedstock shall calculate the CO2 emissions 

associated with that feedstock using Equation MM-9 of this 

section in place of Equation MM-2 of this section. 

CO2j = Feedstockj * EFj * %Volj (Eq. MM-9) 

Where: 

CO2j = Annual CO2 emissions that would result from the 

complete combustion or oxidation of each noncrude feedstock “j” (metric tons). 

Feedstockj = Annual volume of each petroleum product “j” 

that enters the refinery as a feedstock to be 

further refined or otherwise used on site 

(barrels). 

EFj = Non-crude petroleum feedstock-specific CO2

emission factor (metric tons CO2 per barrel). 

%Volj = Percent volume of feedstock “j” that is 

petroleum-based, not including any denaturant 

that may be present in any ethanol product, 

expressed as a fraction (e.g., 75% would be 

expressed as 0.75 in the above equation). 

(3) Calculation Method 2 procedures for products.

(i) A reporter using Calculation Methodology 2 of 

this subpart to determine the emission factor of a 

petroleum product that does not contain denatured ethanol 

must calculate the CO2 emissions associated with that 

Deleted: 2.5% of the volume 

of any ethanol product 

blended into a petroleumbased product to represent 

the 

Deleted: in 

Deleted: i

Deleted: 2.5% of the volume 

of any ethanol product 

blended with the petroleumbased product to represent 

the

Deleted: in 
350

product using Equation MM-10 of this section in place of 

Equation MM-1 of this section. 

CO2i = (Producti * EFi )-(Producti * EFm * %Volm) (Eq. MM-10) 

Where: 

CO2i = Annual CO2 emissions that would result from the 

complete combustion or oxidation of each 

product “i” (metric tons). 

Producti = Annual volume of each petroleum product “i” 

produced, imported, or exported by the 

reporting party (barrels). For refiners, this 

volume only includes products ex refinery gate. 

EFi = Product-specific CO2 emission factor (metric 

tons CO2 per barrel). 

EFm = Default CO2 emission factor from Table MM-2 of 

this subpart that most closely represents the 

component of product “i” that is biomass-based. 

%Volm = Percent volume of petroleum product “i” that is 

biomass-based, expressed as a fraction (e.g., 

75% would be expressed as 0.75 in the above 

equation). 

(ii) In the event that a petroleum product contains 

denatured ethanol, importers and exporters must follow 

Calculation Method 1 procedures in paragraph (h)(1); and 

refineries must sample the petroleum portion of the blended 

biomass-based fuel prior to blending and calculate CO2

emissions using Equation MM-10a of this section.

CO2i = Productp * EFi (Eq. MM-10a)

Where:

CO2i = Annual CO2 emissions that would result from the 

complete combustion or oxidation of each 

biomass-blended fuel “i” (metric tons).

Deleted: not including 2.5% 

of the volume of any ethanol 

product blended with the 

petroleum-based product, 

which represents the 

denaturant in that ethanol 

product, 
351

Productp = Annual volume of the petroleum-based portion of 

each biomass blended fuel “i” produced by the 

refiner (barrels).

EFi = Petroleum product-specific CO2 emission factor 

(metric tons CO2 per barrel). 

(4) Calculation Method 2 procedures for non-crude 

feedstocks.

(i) A refiner using Calculation Method 2 of this 

subpart to determine the emission factor of a non-crude 

petroleum feedstock that does not contain denatured ethanol

must calculate the CO2 emissions associated with that 

feedstock using Equation MM-11 of this section in place of 

Equation MM-2 of this section. 

CO2j = (Feedstockj * EFj)-(Feedstockj * EFm * %Volm)(Eq. MM-11) 

Where: 

CO2j = Annual CO2 emissions that would result from 

the complete combustion or oxidation of each 

non-crude feedstock “j” (metric tons). 

Feedstockj = Annual volume of each petroleum product “j” 

that enters the refinery to be further 

refined or otherwise used on site (barrels). 

EFj = Feedstock-specific CO2 emission factor (metric 

tons CO2 per barrel). 

EFm = Default CO2 emission factor from Table MM-2 of 

this subpart that most closely represents 

the component of petroleum product “j” that 

is biomass-based. 

%Volm = Percent volume of non-crude feedstock “j” that 

is biomass-based, expressed as a fraction 

(e.g., 75% would be expressed as 0.75 in the 

above equation). 

Deleted: ology

Deleted: i 

Deleted: not including 2.5% 

of the volume of any ethanol 

product blended with the 

petroleum-based product, 

which represents the 

denaturant in that ethanol 

product, 
352

(ii) In the event that a non-crude feedstock contains 

denatured ethanol, refiners must follow Calculation Method 

1 procedures in paragraph (h)(2) of this section.

(i) Optional procedures for blended products that do 

not contain biomass.

(1) In the event that a reporter produces, imports, 

or exports a blended product that does not include biomass, 

the reporter may calculate emissions for the blended 

product according to the method in paragraph (i)(2) of this 

section. In the event that a refiner receives a blended 

non-crude feedstock that does not include biomass, the 

refiner may calculate emission for the blended non-crude 

feedstock according to the method in paragraph (i)(3) of 

this section. The procedures in this section may be used 

only if all of the following criteria are met:

(i) The reporter knows the relative proportion of 

each component of the blend (i.e., the mass or volume 

percentage). 

(ii) Each component of blended product “i” or blended 

non-crude feedstock “j” meets the strict definition of a 

product listed in Table MM-1. 

(iii) The blended product or non-crude feedstock is 

not comprised entirely of natural gas liquids.

(iv) The reporter uses Calculation Method 1.
353

(v) Solid components are blended only with other 

solid components.

(2) The reporter must calculate emissions for the 

blended product using Equation MM-12 of this section in 

place of Equation MM-1 of this section.

CO2i = [ * ] C i...n EFi...n ∑ Blending omponent (Eq. MM-12)

Where:

CO2i = Annual CO2 emissions that would result 

from the complete combustion or 

oxidation of a blended product ”i" 

(metric tons).

Blending Componenti...n = Annual volume or mass of each 

blending component that is blended 

(barrels or metric tons). 

EFi...n = CO2 emission factors specific to each 

blending component (metric tons CO2

per barrel or per metric ton of 

product).

n = Number of blending components blended 

into blended product ”i”.

(3) For refineries, the reporter must calculate 

emissions for the blended non-crude feedstock using 

Equation MM-13 of this section in place of Equation MM-2 of 

this section. 

CO2i = [ * ] Compon i...n EFi...n ∑ Blending ent (Eq. MM-13)

Where:

CO2j = Annual CO2 emissions that would result from 

the complete combustion or oxidation of a 
354

blended non-crude feedstock ”j” (metric 

tons).

Blending Componenti...n = Annual volume or mass of each 

blending component that is blended (barrels 

or metric tons). 

EFi...n = CO2 emission factors specific to each blending 

component (metric tons CO2 per barrel or per 

metric ton of product).

n = Number of blending components blended into 

blended non-crude feedstock “j”. 

(4) For refineries, if a blending component “k” used 

in paragraph (i)(2) of this section enters the refinery 

before blending as non-crude feedstock: 

(i) The emissions that would result from the complete 

combustion or oxidation of non-crude feedstock “k” must 

still be calculated separately using Equation MM-2 of this 

section and applied in Equation MM-4 of this section. 

(ii) The quantity of blending component “k” applied 

in Equation MM-12 of this section and the quantity of noncrude feedstock “k” applied in Equation MM-2 of this 

section must be determined using the same method or 

practice.

§98.394 Monitoring and QA/QC requirements.

(a) Determination of quantity. 

(1) The quantity of petroleum products, natural gas 

liquids, biomass, and crude oil shall be determined as 

follows: 
355

(i) Where an appropriate standard method published by 

a consensus-based standards organization exists, such a 

method shall be used. Consensus-based standards 

organizations include, but are not limited to, the 

following: ASTM International, the American National 

Standards Institute (ANSI), the American Gas Association 

(AGA), the American Society of Mechanical Engineers (ASME), 

the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB). 

(ii) Where no appropriate standard method developed 

by a consensus-based standards organization exists, 

industry standard practices shall be followed. 

(iii) For products that are liquid at 60 degrees 

Fahrenheit and one standard atmosphere, all measurements of 

quantity shall be temperature-adjusted and pressureadjusted to these conditions. For all other products, 

reporters shall use appropriate standard conditions 

specified in the standard method; if temperature and 

pressure conditions are not specified in the standard 

method or if a reporter uses an industry standard practice 

to determine quantity, the reporter shall use appropriate 

standard conditions according to established industry 

practices. 
356

(2) All measurement equipment (including, but not 

limited to, flow meters and tank gauges) used for 

compliance with this subpart shall be appropriate for the 

standard method or industry standard practice followed 

under paragraph (a)(1)(i) or (a)(1)(ii) of this section. 

(b) Equipment Calibration. 

(1) All measurement equipment shall be calibrated 

prior to its first use for reporting under this subpart, 

using an appropriate standard method published by a 

consensus based standards organization or according to the 

equipment manufacturer’s directions. 

(2) Measurement equipment shall be recalibrated at 

the minimum frequency specified by the standard method used 

or by the equipment manufacturer’s directions. 

(c) Procedures for Calculation Methodology 2 of this 

subpart. 

(1) Reporting parties shall collect one sample of 

each petroleum product or natural gas liquid on any day of 

each calendar month of the reporting year in which the 

quantity of that product was measured in accordance with 

the requirements of this subpart. For example, if a given 

product was measured as entering the refinery continuously 

throughout the reporting year, twelve samples of that 

product shall be collected over the reporting year, one on 
357

any day of each calendar month of that year. If a given 

product was only measured from April 15 through June 10 of 

the reporting year, a refiner would collect three samples 

during that year, one during each of the calendar months of 

April, May and June on a day when the product was measured 

as either entering or exiting the refinery. Each sample 

shall be collected using an appropriate standard method 

published by a consensus-based standards organization. 

(2) Mixing and handling of samples shall be performed 

using an appropriate standard method published by a 

consensus-based standards organization. 

(3) Density measurement. 

(i) For all products that are not solid, reporters 

shall test for density using an appropriate standard method 

published by a consensus-based standards organization. 

(ii) The density value for a given petroleum product 

shall be generated by either making a physical composite of 

all of the samples collected for the reporting year and 

testing that single sample or by measuring the individual 

samples throughout the year and defining the representative 

density value for the sample set by numerical means, i.e., 

a mathematical composite. If a physical composite is 

chosen as the option to obtain the density value, the 

reporter shall submit each of the individual samples 
358

collected during the reporting year to the laboratory 

responsible for generating the composite sample. 

(iii) For physical composites, the reporter shall 

handle the individual samples and the laboratory shall mix 

them in accordance with an appropriate standard method 

published by a consensus-based standards organization. 

(iv) All measurements of density shall be 

temperature-adjusted and pressure-adjusted to the 

conditions assumed for determining the quantities of the 

product reported under this subpart. 

(4) Carbon share measurement. 

(i) Reporters shall test for carbon share using an 

appropriate standard method published by a consensus-based 

standards organization. 

(ii) If a standard method that involves gas 

chromatography is used to determine the percent mass of 

each component in a product, the molecular formula for each 

component shall be obtained from the information provided 

in the standard method and the atomic mass of each element 

in a given molecular component shall be obtained from the 

periodic table of the elements. 

(iii) The carbon share value for a given petroleum 

product shall be generated by either making a physical 

composite of all of the samples collected for the reporting 
359

year and testing that single sample or by measuring the 

individual samples throughout the year and defining the 

representative carbon share value for the sample set by 

numerical means, i.e., a mathematical composite. If a 

physical composite is chosen as the option to obtain the 

carbon share value, the reporter shall submit each of the 

individual samples collected during the reporting year to 

the laboratory responsible for generating the composite 

sample. 

(iv) For physical composites, the reporter shall 

handle the individual samples and the laboratory shall mix 

them in accordance with an appropriate standard method 

published by a consensus-based standards organization. 

(d) Measurement of API gravity and sulfur content of 

crude oil. 

(1) A representative sample or multiple 

representative samples of each batch of crude oil shall be 

taken according to an appropriate standard method published 

by a consensus-based standards organization. 

(2) Samples shall be handled according to an 

appropriate standard method published by a consensus-based 

standards organization. 

(3) API gravity shall be measured using an 

appropriate standard method published by a consensus-based 

Deleted: S

Deleted: s
360

standards organization. The weighted average API gravity 

for each batch shall be calculated by multiplying the 

volume associated with each representative sample by the 

API gravity, adding these values for all the samples, and 

then dividing that total value by the volume of the batch. 

(4) Sulfur content shall be measured using an 

appropriate standard method published by a consensus-based 

standards organization. The weighted average sulfur 

content for each batch shall be calculated by multiplying 

the volume associated with each representative sample by 

the sulfur content, adding these values for all the 

samples, and then dividing that total value by the volume 

of the batch. 

(5) All measurements shall be temperature-adjusted 

and pressure-adjusted to the conditions assumed for 

determining the quantities of crude oil reported under this 

subpart. 

§98.395 Procedures for estimating missing data. 

(a) Determination of quantity. Whenever the quality 

assurance procedures in §98.394(a) cannot be followed to 

measure the quantity of one or more petroleum products, 

natural gas liquids, types of biomass, feedstocks, or crude 

oil batches during any period (e.g., if a meter 
361

malfunctions), the following missing data procedures shall 

be used: 

(1) For quantities of a product that are purchased or 

sold, a period of missing data shall be substituted using a 

reporter’s established procedures for billing purposes in 

that period as agreed to by the party selling or purchasing 

the product. 

(2) For quantities of a product that are not 

purchased or sold but of which the custody is transferred, 

a period of missing data shall be substituted using a 

reporter’s established procedures for tracking purposes in 

that period as agreed to by the party involved in custody 

transfer of the product. 

(b) Determination of emission factor. Whenever any 

of the procedures in §98.394(c) cannot be followed to 

develop an emission factor for any reason, Calculation 

Methodology 1 of this subpart must be used in place of 

Calculation Methodology 2 of this subpart for the entire 

reporting year. 

(c) Determination of API gravity and sulfur content 

of crude oil. For missing data on sulfur content or API 

gravity, the substitute data value shall be the arithmetic 

average of the quality-assured values of API gravity or 

sulfur content in the batch preceding and the batch 
362

immediately following the missing data incident. If no 

quality-assured data are available prior to the missing 

data incident, the substitute data value shall be the first 

quality-assured values for API gravity and sulfur content 

obtained from the batch after the missing data period. 

§98.396 Data reporting requirements. 

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

the following requirements apply: 

(a) Refiners shall report the following information 

for each facility: 

(1) For each petroleum product or natural gas liquid 

listed in table MM-1 of this subpart that enters the 

refinery to be further refined or otherwise used on site, 

report the annual quantity in metric tons or barrels by 

each quantity measurement standard method or other industry 

standard practice used. For natural gas liquids, quantity 

shall reflect the individual components of the product. 

(2) For each petroleum product or natural gas liquid 

listed in Table MM-1 of this subpart that enters the 

refinery to be further refined or otherwise used on site, 

report the annual quantity in metric tons or barrels. For 

natural gas liquids, quantity shall reflect the individual 

components of the product. 
363

(3) For each feedstock reported in paragraph (a)(2) 

of this section that was produced by blending a petroleumbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (a)(2) of this 

section that is petroleum-based (excluding any denaturant 

that may be present in any ethanol product). 

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(1) of this section. 

(5) For each petroleum product and natural gas liquid 

(ex refinery gate) listed in Table MM-1 of this subpart, 

report the annual quantity in metric tons or barrels by 

each quantity measurement standard method or other industry 

standard practice used. For natural gas liquids, quantity 

shall reflect the individual components of the product. 

Petroleum products and natural gas liquids that enter the 

refinery, but are not reported in (a)(1), shall not be 

reported under this paragraph.

(6) For each petroleum product and natural gas liquid 

(ex refinery gate) listed in Table MM-1 of this subpart, 

report the annual quantity in metric tons or barrels. For 

natural gas liquids, quantity shall reflect the individual 

components of the product. Petroleum products and natural 
364

gas liquids that enter the refinery, but are not reported 

in (a)(2), shall not be reported under this paragraph.

(7) For each product reported in paragraph (a)(6) of 

this section that was produced by blending a petroleumbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (a)(6) of this 

section that is petroleum-based (excluding any denaturant 

that may be present in any ethanol product). 

(8) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(5) of this section. 

(9) For every feedstock reported in paragraph (a)(2) 

of this section for which Calculation Methodology 2 of this 

subpart was used to determine an emissions factor, report: 

(i) The number of samples collected according to 

§98.394(c) 

(ii) The sampling standard method used. 

(iii) The carbon share test results in percentmass. 

(iv) The standard method used to test carbon share. 

(v) The calculated CO2 emissions factor in metric 

tons. 

(10) For every non-solid feedstock reported in 

paragraph (a)(2) of this section for which Calculation 
365

Methodology 2 of this subpart was used to determine an 

emissions factor, report: 

(i) The density test results in metric tons per 

barrel. 

(ii) The standard method used to test density. 

(11) For every petroleum product and natural gas 

liquid reported in paragraph (a)(6) of this section for 

which Calculation Methodology 2 of this subpart was used to 

determine an emissions factor, report: 

(i) The number of samples collected according to 

§98.394(c). 

(ii) The sampling standard method used. 

(iii) The carbon share test results in percentmass. 

(iv) The standard method used to test carbon share. 

(v) The calculated CO2 emissions factor in metric tons 

CO2 per barrel or per metric ton of product. 

(12) For every non-solid petroleum product and 

natural gas liquid reported in paragraph (a)(6) for which 

Calculation Method 2 was used to determine an emissions 

factor, report: 

(i) The density test results in metric tons per 

barrel. 

(ii) The standard method used to test density. 
366

(13) For each specific type of biomass that enters 

the refinery to be co-processed with petroleum feedstocks 

to produce a petroleum product reported in paragraph (a)(6) 

of this section, report the annual quantity in metric tons 

or barrels by each quantity measurement standard method or 

other industry standard practice used. 

(14) For each specific type of biomass that enters 

the refinery to be co-processed with petroleum feedstocks 

to produce a petroleum product reported in paragraph (a)(6) 

of this section, report the annual quantity in metric tons 

or barrels. 

(15) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(13) of this section. 

(16) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

petroleum product and natural gas liquid (ex refinery gate) 

reported in paragraph (a)(6) of this section, calculated 

according to §98.393(a) or (h). 

(17) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

feedstock reported in paragraph (a)(2) of this section, 

calculated according to §98.393(b) or (h). 
367

(18) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

type of biomass feedstock co-processed with petroleum 

feedstocks reported in paragraph (a)(13) of this section, 

calculated according to §98.393(c). 

(19) The sum of CO2 emissions that would result from 

the complete combustion or oxidation of all products, 

calculated according to §98.393(d). 

(20) All of the following information for all crude 

oil feedstocks used at the refinery: 

(i) Batch volume in barrels. 

(ii) Weighted average API gravity of the batch at the 

point of entry at the refinery. 

(iii) Weighted average sulfur content of the batch at 

the point of entry at the refinery. 

(iv) Country of origin of the batch, if known. 

(21) The quantity of bulk NGLs in metric tons or 

barrels received for processing during the reporting year. 

(b) In addition to the information required by 

§98.3(c), each importer shall report all of the following 

information at the corporate level: 

(1) For each petroleum product and natural gas liquid 

listed in Table MM-1 of this subpart, report the annual 

quantity in metric tons or barrels by each quantity 

Deleted: S
368

measurement standard method or other industry standard 

practice used. For natural gas liquids, quantity shall 

reflect the individual components of the product. 

(2) For each petroleum product and natural gas liquid 

listed in Table MM-1 of this subpart, report the annual 

quantity in metric tons or barrels. For natural gas 

liquids, quantity shall reflect the individual components 

of the product as listed in Table MM-1 of this subpart. 

(3) For each product reported in paragraph (b)(2) of 

this section that was produced by blending a petroleumbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (b)(2) of this 

section that is petroleum-based (excluding any denaturant 

that may be present in any ethanol product). 

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (b)(1) of this section. 

(5) For each product reported in paragraph (b)(2) of 

this section for which Calculation Methodology 2 of this 

subpart used was used to determine an emissions factor, 

report: 

(i) The number of samples collected according to 

§98.394(c) 

(ii) The sampling standard method used. 
369

(iii) The carbon share test results in percent mass. 

(iv) The standard method used to test carbon share. 

(v) The calculated CO2 emissions factor in metric tons 

CO2 per barrel or per metric ton of product. 

(6) For each non-solid product reported in paragraph 

(b)(2) of this section for which Calculation Methodology 2 

of this subpart was used to determine an emissions factor, 

report: 

(i) The density test results in metric tons per 

barrel. 

(ii) The standard method used to test density. 

(7) The CO2 emissions in metric tons that would result 

from the complete combustion or oxidation of each imported 

petroleum product and natural gas liquid reported in 

paragraph (b)(2) of this section, calculated according to 

§98.393(a). 

(8) The sum of CO2 emissions that would result from 

the complete combustion oxidation of all imported products, 

calculated according to §98.393(e). 

(c) In addition to the information required by 

§98.3(c), each exporter shall report all of the following 

information at the corporate level: 

(1) For each petroleum product and natural gas liquid 

listed in Table MM-1 of this subpart, report the annual 
370

quantity in metric tons or barrels by each quantity 

measurement standard method or other industry standard 

practice used. For natural gas liquids, quantity shall 

reflect the individual components of the product. 

(2) For each petroleum product and natural gas liquid 

listed in Table MM-1 of this subpart, report the annual 

quantity in metric tons or barrels. For natural gas 

liquids, quantity shall reflect the individual components 

of the product. 

(3) For each product reported in paragraph (c)(2) of 

this section that was produced by blending a petroleumbased product with a biomass-based product, report the 

percent of the volume reported in paragraph (c)(2) of this 

section that is petroleum based (excluding any denaturant 

that may be present in any ethanol product). 

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (c)(1) of this section. 

(5) For each product reported in paragraph (c)(2) of 

this section for which Calculation Methodology 2 of this 

subpart was used to determine an emissions factor, report: 

(i) The number of samples collected according to 

§98.394(c). 

(ii) The sampling standard method used. 
371

(iii) The carbon share test results in percentmass. 

(iv) The standard method used to test carbon share. 

(v) The calculated CO2 emissions factor in metric tons 

CO2 per barrel or per metric ton of product. 

(6) For each non-solid product reported in paragraph 

(c)(2) of this section for which Calculation Methodology 2 

of this subpart used was used to determine an emissions 

factor, report: 

(i) The density test results in metric tons per 

barrel. 

(ii) The standard method used to test density. 

(7) The CO2 emissions in metric tons that would result 

from the complete combustion or oxidation of for each 

exported petroleum product and natural gas liquid reported 

in paragraph (c)(2) of this section, calculated according 

to §98.393(a). 

(8) The sum of CO2 emissions that would result from 

the complete combustion or oxidation of all exported 

products, calculated according to §98.393(e). 

(d) Blended non-crude feedstock and products.

(1) Refineries, exporters, and importers must report 

the following information for each blended product and noncrude feedstock where emissions were calculated according 

to §98.393(i): 
372

(i) Volume or mass of each blending component.

(ii) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each 

blended non-crude feedstock or product, using Equation MM12 or Equation MM-13 of this section.

(2) For a product that enters the refinery to be 

further refined or otherwise used on site that is a blended 

non-crude feedstock, refiners must meet the reporting 

requirements of paragraphs (a)(1) and (a)(2) of this 

section by reflecting the individual components of the 

blended non-crude feedstock.

(3) For a product that is produced, imported, or 

exported that is a blended product, refiners, importers, 

and exporters must meet the reporting requirements of 

paragraphs (a)(5), (a)(6), (b)(1), (b)(2), (c)(1), and 

(c)(2) of this section, as applicable, by reflecting the 

individual components of the blended product.

§98.397 Records that must be retained.

(a) All reporters shall retain copies of all reports 

submitted to EPA under §98.396. In addition, all reporters 

shall maintain sufficient records to support information 

contained in those reports, including but not limited to 

information on the characteristics of their feedstocks and 

products. 
373

(b) Reporters shall maintain records to support 

quantities that are reported under this subpart, including 

records documenting any estimations of missing data and the 

number of calendar days in the reporting year for which 

substitute data procedures were followed. For all 

quantities of petroleum products, natural gas liquids, 

biomass, and feedstocks, reporters shall maintain metering, 

guaging, and other records normally maintained in the 

course of business to document product and feedstock flows 

including the date of initial calibration and the frequency 

of recalibration for the measurement equipment used 

(c) Reporters shall retain laboratory reports, 

calculations and worksheets used to estimate the CO2

emissions of the quantities of petroleum products, natural 

gas liquids, biomass, and feedstocks reported under this 

subpart. 

(d) Reporters shall maintain laboratory reports, 

calculations and worksheets used in the measurement of 

density and carbon share for any petroleum product or 

natural gas liquid for which CO2 emissions were calculated 

using Calculation Methodology 2. 

(e) Estimates of missing data shall be documented and 

records maintained showing the calculations. 

Deleted: (e) Reporters shall 

maintain laboratory reports, 

calculations and worksheets 

used in the measurement of 

API gravity and sulfur 

content for every crude oil 

batch reported under this 

subpart.¶

Deleted: f
374

(f) Reporters described in this subpart shall also 

retain all records described in §98.3(g). 

§98.398 Definitions.

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.

Batch means up to a calendar month of crude oil volume 

from a single country of origin or up to a calendar month 

of crude oil volume for which the country of origin is 

unknown.

Table MM-1 of Subpart MM—Default Factors for Petroleum 

Products and Natural Gas Liquids1,2

Products 

Column A: 

Density 

(metric 

tons/bbl) 

Column B: 

Carbon 

Share 

(% of 

mass) 

Column C: 

Emission Factor 

(metric tons 

CO2/bbl) 

Finished Motor Gasoline 

Conventional - Summer 

Regular 0.1181 86.66 0.3753

Midgrade 0.1183 86.63 0.3758

Premium 0.1185 86.61 0.3763

Conventional - Winter 

Regular 0.1155 86.50 0.3663

Midgrade 0.1161 86.55 0.3684

Premium 0.1167 86.59 0.3705

Reformulated - Summer 

Regular 0.1167 86.13 0.3686

Midgrade 0.1165 86.07 0.3677

Premium 0.1164 86.00 0.3670

Reformulated - Winter 

Regular 0.1165 86.05 0.3676

Midgrade 0.1165 86.06 0.3676

Premium 0.1166 86.06 0.3679

Gasoline—Other 0.1185 86.61 0.3763

Blendstocks 

Deleted: g

Deleted: All 
375

Products 

Column A: 

Density 

(metric 

tons/bbl) 

Column B: 

Carbon 

Share 

(% of 

mass) 

Column C: 

Emission Factor 

(metric tons 

CO2/bbl) 

CBOB—Summer 

Regular 0.1181 86.66 0.3753

Midgrade 0.1183 86.63 0.3758

Premium 0.1185 86.61 0.3763

CBOB—Winter 

Regular 0.1155 86.50 0.3663

Midgrade 0.1161 86.55 0.3684

Premium 0.1167 86.59 0.3705

RBOB—Summer 

Regular 0.1167 86.13 0.3686

Midgrade 0.1165 86.07 0.3677

Premium 0.1164 86.00 0.3670

RBOB—Winter 

Regular 0.1165 86.05 0.3676

Midgrade 0.1165 86.06 0.3676

Premium 0.1166 86.06 0.3679

Blendstocks—Other 0.1185 86.61 0.3763

Oxygenates 

Methanol 0.1268 37.48 0.1743

GTBA 0.1257 64.82 0.2988

MTBE 0.1181 68.13 0.2950

ETBE 0.1182 70.53 0.3057

TAME 0.1229 70.53 0.3178

DIPE 0.1156 70.53 0.2990

Distillate Fuel Oil 

Distillate No. 1 

Ultra Low Sulfur 0.1346 86.40 0.4264

Low Sulfur 0.1346 86.40 0.4264

High Sulfur 0.1346 86.40 0.4264

Distillate No. 2 

Ultra Low Sulfur 0.1342 87.30 0.4296

Low Sulfur 0.1342 87.30 0.4296

High Sulfur 0.1342 87.30 0.4296

Distillate Fuel Oil 

No. 4 0.1452 86.47 0.4604

Residual Fuel Oil No. 

5 (Navy Special) 0.1365 85.67 0.4288

Residual Fuel Oil No. 

6 (a.k.a. Bunker C) 0.1528 84.67 0.4744

Kerosene-Type Jet 

Fuel 0.1294 86.30 0.4095

Kerosene 0.1346 86.40 0.4264
376

Products 

Column A: 

Density 

(metric 

tons/bbl) 

Column B: 

Carbon 

Share 

(% of 

mass) 

Column C: 

Emission Factor 

(metric tons 

CO2/bbl) 

Diesel—Other 0.1452 86.47 0.4604

Petrochemical Feedstocks 

Naphthas (< 401°F) 0.1158 84.11 0.3571

Other Oils (> 401°F) 0.1390 87.30 0.4450

Unfinished Oils

Heavy Gas Oils 0.1476 85.80 0.4643

Residuum 0.1622 85.70 0.5097

Other Petroleum Products and Natural Gas Liquids 

Aviation Gasoline 0.1120 85.00 0.3490

Special Naphthas 0.1222 84.76 0.3798

Lubricants 0.1428 85.80 0.4492

Waxes 0.1285 85.30 0.4019

Petroleum Coke 0.1818 92.28 0.6151

Asphalt and Road Oil 0.1634 83.47 0.5001

Still Gas 0.1405 77.70 0.4003

Ethane 0.0866 79.89 0.2537

Ethylene 0.0903 85.63 0.2835

Propane 0.0784 81.71 0.2349

Propylene 0.0803 85.63 0.2521

Butane 0.0911 82.66 0.2761

Butylene 0.0935 85.63 0.2936

Isobutane 0.0876 82.66 0.2655

Isobutylene 0.0936 85.63 0.2939

Pentanes Plus 0.1055 83.63 0.3235

Miscellaneous 

Products 0.1380 85.49 0.4326

1. In the case of products blended with some portion of biomass-based fuel, the 

carbon share in Table MM-1 of this subpart represents only the petroleum-based 

components. 

2. Products that are derived entirely from biomass should not be reported, but 

products that were derived from both biomass and a petroleum product (i.e., coprocessed) should be reported as the petroleum product that it most closely 

represents.

Table MM-2 of Subpart MM—Default Factors for Biomass-Based 

Fuels and Biomass 

Biomass-Based Fuel and 

Biomass 

Column A: 

Density 

(metric 

tons/bbl) 

Column B: 

Carbon 

Share 

(% of 

mass) 

Column C: 

Emission Factor 

(metric tons CO2/bbl) 
377

Biomass-Based Fuel and 

Biomass 

Column A: 

Density 

(metric 

tons/bbl) 

Column B: 

Carbon 

Share 

(% of 

mass) 

Column C: 

Emission Factor 

(metric tons CO2/bbl) 

Ethanol (100%) 

0.1267 52.14 0.2422 

Biodiesel 

(100%, methyl ester) 

0.1396 77.30 0.3957 

Rendered Animal Fat 

0.1333 76.19 0.3724 

Vegetable Oil 

0.1460 76.77 0.4110 

Subpart NN—Suppliers of Natural Gas and Natural Gas Liquids 

§98.400 Definition of the source category.

This supplier category consists of natural gas liquids 

fractionators and local natural gas distribution companies. 

(a) Natural gas liquids fractionators are 

installations that fractionate natural gas liquids (NGLs) 

into their consitutent liquid products (ethane, propane, 

normal butane, isobutane or pentanes plus) for supply to 

downstream facilities. 

(b) Local Distribution Companies (LDCs)are companies 

that own or operate distribution pipelines, not interstate 

pipelines or intrastate pipelines, that physically deliver 

natural gas to end users and that are regulated as separate 

operating companies by State public utility commissions or 

that operate as independent municipally-owned distribution 

systems. 
378

(c) This supply category does not consist of the 

following facilities: 

(1) Field gathering and boosting stations. 

(2) Natural gas processing plants that separate NGLs 

from natural gas and produce bulk or y-grade NGLs but do 

not fractionate these NGLs into their constituent products. 

(3) Facilities that meet the definition of refineries 

and report under subpart MM of this part. 

(4) Facilities that meet the definition of 

petrochemical plants and report under subpart X of this 

part. 

§98.401 Reporting threshold.

Any supplier of natural gas and natural gas liquids 

that meets the requirements of §98.2(a)(4) must report GHG 

emissions. 

§98.402 GHGs to report.

(a) NGL fractionators must report the CO2 emissions 

that would result from the complete combustion or oxidation 

of the annual quantity of ethane, propane, normal butane, 

isobutane, and pentanes plus that is produced and sold or 

delivered to others. 

(b) LDCs must report the CO2 emissions that would 

result from the complete combustion or oxidation of the 
379

annual volumes of natural gas provided to end-users on 

their distribution systems. 

§98.403 Calculating GHG emissions.

(a) LDCs and fractionators shall, for each individual 

product reported under this part, calculate the estimated 

CO2 emissions that would result from the complete combustion 

or oxidation of the products supplied using either of 

Calculation Methodology 1 or 2 of this subpart: 

(1) Calculation Methodology 1. NGL fractionators 

shall estimate CO2 emissions that would result from the 

complete combustion or oxidation of the product(s) supplied 

using Equation NN-1 of this section. LDCs shall estimate 

CO2 emissions that would result from the complete combustion 

or oxidation of the product received at the city gate using 

Equation NN-1. For each product, use the default value for 

higher heating value and CO2 emission factor in Table NN-1 

of this subpart. Alternatively, for each product, a 

reporter-specific higher heating value and CO2 emission 

factor may be used, in place of one or both defaults 

provided they are developed using methods outlined in 

§98.404. For each product, you must use the same volume 

unit throughout the equation. 

h h

3 CO2i 1x10 * Fuel *HHV *EF ∑ h

−

= (Eq. NN-1) 
380

Where: 

CO2i = Annual CO2 mass emissions that would result from 

the combustion or oxidation of each product “h” 

for redelivery to all recipients (metric tons). 

Fuelh = Total annual volume of product “h” supplied 

(volume per year, in thousand standard cubic 

feet (Mscf) for natural gas and bbl for NGLs). 

HHVh = Higher heating value of product “h” supplied 

(MMBtu/ Mscf or MMBtu/bbl). 

EFh = CO2 emission factor of product "h" (kg 

CO2/MMBtu). 

1 x 10-3 = Conversion factor from kilograms to metric tons 

(MT/kg). 

(2) Calculation Methodology 2. NGL fractionators 

shall estimate CO2 emissions that would result from the 

complete combustion or oxidation of the product(s) supplied 

using Equation NN-2 of this section. LDCs shall estimate 

CO2 emissions that would result from the complete combustion 

or oxidation of the product received at the city gate using 

Equation NN-2. For each product, use the default CO2

emission factor found in Table NN-2 of this subpart. 

Alternatively, for each product, a reporter-specific CO2

emission factor may be used in place of the default factor, 

provided it is developed using methods outlined in §98.404. 

For each product, you must use the same volume unit 

throughout the equation. 

=∑hF h EFh CO uel * 2i (Eq. NN-2) 
381

Where: 

CO2i = Annual CO2 mass emissions that would result from 

the combustion or oxidation of each product “h” 

(metric tons) 

Fuelh = Total annual volume of product “h” supplied (bbl 

or Mscf per year) 

EFh = CO2 emission factor of product "h" (MT CO2/bbl, or 

MT CO2/Mscf) 

(b) Each LDC shall follow the procedures below. 

(1) For natural gas that is received for redelivery 

to downstream gas transmission pipelines and other local 

distribution companies, use eEquation NN-3 of this section 

and the default values for the CO2 emission factors found in 

Table NN-2 of this subpart. Alternatively, reporterspecific CO2 emission factors may be used, provided they 

are developed using methods outlined in §98.404. 

CO2j = Fuel *EF (Eq. NN-3) 

Where: 

CO2j = Annual CO2 mass emissions that would result from 

the combustion or oxidation of natural gas for 

redelivery to transmission pipelines or other 

LDCs (metric tons). 

Fuel = Total annual volume of natural gas supplied (Mscf 

per year). 

EF = Fuel-specific CO2 emission factor (MT CO2/Mscf). 

(2) For natural gas delivered to each meter 

registering a supply equal to or greater than 460,000 Mscf 

per year, use Equation NN-4 of this section and the default 
382

values for the CO2 emission factors found in Table NN-2 of 

this subpart. 

Alternatively, reporter-specific CO2 emission factors 

may be used, provided they are developed using methods 

outlined in §98.404. 

CO2k = Fuel*EF (Eq. NN-4) 

Where: 

CO2k = Annual CO2 mass emissions that would result from 

the combustion or oxidation of natural gas 

received by end-users that receive a supply equal 

to or greater than 460,000 Mscf per year (metric 

tons). 

Fuel = Total annual volume of natural gas supplied (Mscf 

per year). 

EF = Fuel-specific CO2 emission factor (MT CO2/Mscf). 

(3) For natural gas received by the LDC at the city 

gate that is injected into on-system storage, and/or 

liquefied and stored, use Equation NN-5 of this section and 

the default value for the CO2 emission factors found in 

Table NN-2 of this subpart. Alternatively, a reporterspecific CO2 emission factor may be used, provided it is 

developed using methods outlined in §98.404. 

CO2l = [Fuel1 − Fuel2]*EF (Eq. NN-5) 

Where: 

CO2l = Annual CO2 mass emissions that would result from 

the combustion or oxidation of the net natural 

gas that is liquefied and/or stored and not used 

for deliveries by the LDC within the reported 

year (metric tons). 
383

Fuel1 = Total annual volume of natural gas received by 

the LDC at the city gate and stored on-system or 

liquefied and stored in the reporting year (Mscf 

per year). 

Fuel2 = Total annual volume of natural gas that is used 

for deliveries in the reporting year that was not 

otherwise accounted for in Equation NN-1 or NN-2 

of this section (Mscf per year). This primarily 

includes natural gas previously stored on-system 

or liquefied and stored that is removed from 

storage and used for deliveries to customers or 

other LDCs by the LDC within the reporting year. 

This also includes natural gas that bypassed the 

city gate and was delivered directly to LDC 

systems from producers or natural gas processing 

plants from local production. 

EF = Fuel-specific CO2 emission factor (MT CO2/Mscf). 

(4) Calculate the total CO2 emissions that would 

result from the complete combustion or oxidation of the 

annual supply of natural gas to end-users using Equation 

NN-6 of this section. 

CO2 = ∑ CO2i − ∑ CO2j − ∑ CO2k −∑ CO2l (Eq. NN-6) 

Where: 

CO2 = Annual CO2 mass emissions that would result from 

the combustion or oxidation of natural gas 

delivered to LDC customers not covered in 

paragraph (b)(2) of this section (metric tons). 

CO2i = Annual CO2 mass emissions that would result from 

the combustion or oxidation of natural gas 

received at the city gate as calculated in 

paragraph (a)(1) or (a)(2) of this section 

(metric tons). 

CO2j = Annual CO2 mass emissions that would result from 

the combustion or oxidation of natural gas 

delivered to transmission pipelines or other LDCs 

as calculated in paragraph (b)(1) of this section 

(metric tons). 
384

CO2k = Annual CO2 mass emissions that would result from 

the combustion or oxidation of natural gas 

received by end-users that receive a supply equal 

to or greater than 460,000 Mscf per year as 

calculated in paragraph (b)(2) of this section 

(metric tons). 

CO2l = Annual CO2 mass emissions that would result from 

the combustion or oxidation of natural gas 

received by the LDC and liquefied and/or stored 

but not used for deliveries within the reported 

year as calculated in paragraph (b)(3) of this 

section (metric tons). 

(c) Each NGL fractionator shall follow the following 

procedures. 

(1) For fractionated NGLs received by the reporter 

from other NGL fractionators, you shall use Equation NN-7 

of this section and the default values for the CO2 emission 

factors found in Table NN-2 of this subpart. 

Alternatively, reporter-specific CO2 emission factors 

may be used, provided they are developed using methods 

outlined in §98.404. 

=∑gCO2m Fuelg *EFg (Eq. NN-7) 

Where: 

CO2m = Annual CO2 mass emissions that would result from 

the combustion or oxidation of each fractionated 

NGL product "g" received from other fractionators 

(metric tons). 

Fuelg = Total annual volume of each NGL product "g" 

received (bbls). 

EFg = Fuel-specific CO2 emission factor of NGL product 

“g” (MT CO2/bbl). 
385

(2) Calculate the total CO2 equivalent emissions that 

would result from the combustion or oxidation of 

fractionated NGLs supplied less the quantity received by 

other fractionators using Equation NN-8 of this section. 

CO2 = CO2i − CO2m (Eq. NN-8) 

Where: 

CO2 = Annual CO2 mass emissions that would result from 

the combustion or oxidation of fractionated NGLs 

delivered to customers or on behalf of customers 

(metric tons). 

CO2i = Annual CO2 mass emissions that would result from 

the combustion or oxidation of fractionated NGLs 

delivered to all customers or on behalf of 

customers as calculated in paragraph (a)(1) or 

(a)(2) of this section (metric tons). 

CO2m = Annual CO2 mass emissions that would result from 

the combustion or oxidation of fractionated NGLs 

received from other fractionators and calculated 

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

tons). 

§98.404 Monitoring and QA/QC requirements.

(a) Determination of quantity. 

(1) NGL fractionators and LDCs shall determine the 

quantity of NGLs and natural gas using methods in common 

use in the industry for billing purposes as audited under 

existing Sarbanes Oxley regulationn. 

(i) Where an appropriate standard method published by 

a consensus-based standards organization exists, such a 

method shall be used. Consensus-based standards 

organizations include, but are not limited to, the 
386

following: ASTM International, the American National 

Standards Institute (ANSI), the American Gas Association 

(AGA), the American Society of Mechanical Engineers (ASME), 

the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB). 

(ii) Where no appropriate standard method developed 

by a consensus-based standards organization exists, 

industry standard practices shall be followed. 

(2) NGL fractionators and LDCs shall base the minimum 

frequency of the product quantity measurements, to be 

summed to the annual quantity reported, on the reporter’s 

standard practices for commercial operations. 

(i) For NGL fractionators the minimum frequency of 

measurements shall be the measurements taken at custody 

transfers summed to the annual reportable volume. 

(ii) For natural gas the minimum frequency of 

measurement shall be based on the LDC’s standard 

measurement schedules used for billing purposes and summed 

to the annual reportable volume. 

(3) NGL fractionators shall use measurement for NGLs 

at custody tranfer meters or at such meters that are used 

to determine the NGL product slate delivered from the 

fractionation facility. 
387

(4) If a NGL fractionator supplies a product not 

listed in Table NN-1 of this subpart that is a mixture or 

blend of two or more products listed in Tables NN-1 and NN2 of this subpart, the NGL fractionator shall report the 

quantities of the constituents of the mixtures or blends 

separately. 

(5) For an LDC using Equation NN-1 or NN-2 of this 

subpart, the point(s) of measurement for the natural gas 

volume supplied shall be the LDC city gate meter(s). 

(i) If the LDC makes its own quantity measurements 

according to established business practices, its own 

measurements shall be used. 

(ii) If the LDC does not make its own quantity 

measurements according to established business practices, 

it shall use its delivering pipeline invoiced measurements 

for natural gas deliveries to the LDC city gate, used in 

determining daily system sendout. 

(6) An LDC using Equation NN-3 of this subpart shall 

measure natural gas at the custody transfer meters. 

(7) An LDC using Equation NN-4 of this subpart shall 

measure natural gas at the customer meters. The reporter 

shall consider the volume delivered through a single 

particluar meter at a single particular location as the 

volume delivered to an individual end-user. 
388

(8) An LDC using Equation NN-5 of this subpart shall 

measure natural gas as follows: 

(i) Fuel1 shall be measured at the on-system storage 

injection meters and/or at the meters measuring natural gas 

to be liquefied. 

(ii) Fuel2 shall be measured at the meters used for 

measuring on-system storage withdrawals and/or LNG 

vaporization injection. If Fuel2 is from a source other 

than storage, the appropriate meter shall be used to 

measure the quantity. 

(9) An LDC shall measure all natural gas under the 

following standard industry temperature and pressure 

conditions: cubic foot of gas at a temperature of 60 

degrees Fahrenheit and at an absolute pressure of fourteen 

and seventy-three hundredths (14.73) pounds per square 

inch. 

(b) Determination of higher heating values (HHV). 

(1) When a reporter uses the default HHV provided in 

this section to calculate Equation NN-1 of this subpart, 

the appropriate value shall be taken from Table NN-1 of 

this subpart. 

(2) When a reporter uses a reporter-specific HHV to 

calculate Equation NN-1 of this subpart, an appropriate 

standard test published by a consensus-based standards 
389

organization shall be used. Consensus-based standards 

organizations include, but are not limited to, the 

following: AGA and GPA. 

(i) If an LDC makes its own HHV measurements 

according to established business practices, then its own 

measurements shall be used. 

(ii) If an LDC does not make its own measurements 

according to established business practices, it shall use 

its delivering pipeline measurements. 

(c) Determination of emission factor (EF). 

(1) When a reporter used the default EF provided in 

this section to calculate Equation NN-1 of this subpart, 

the appropriate value shall be taken from Table NN-1 of 

this subpart. 

(2) When a reporter used the default EF provided in 

this section to calculate Equation NN-2, NN-3, NN-4, NN-5, 

or NN-7 of this subpart, the appropriate value shall be 

taken from Table NN-2 of this subpart. 

(3) When a reporter uses a reporter-specific EF, the 

reporter shall use an appropriate standard method published 

by a consensus-based standards organization to conduct 

compositional analysis necessary to determine reporterspecific CO2 emission factors. Consensus-based standards 
390

organizations include, but are not limited to, the 

following: AGA and GPA. 

(d) Equipment Calibration. 

(1) Equipment used to measure quantities in Equations 

NN-1, NN-2, and NN-5 of this subpart shall be calibrated 

prior to its first use for reporting under this subpart, 

using a suitable standard method published by a consensus 

based standards organization or according to the equipment 

manufacturer’s directions. 

(2) Equipment used to measure quantities in Equations 

NN-1, NN-2, and NN-5 of this subpart shall be recalibrated 

at the frequency specified by the standard method used or 

by the manufacturer’s directions. 

§98.405 Procedures for estimating missing data. 

(a) Whenever a quality-assured value of the quantity 

of natural gas liquids or natural gas supplied during any 

period is unavailable (e.g., if a flow meter malfunctions), 

a substitute data value for the missing quantity 

measurement must be used in the calculations according to 

paragraphs (b) and (c) of this section. 

(b) Determination of quantity. 

(1) NGL fractionators shall substitute meter records 

provided by pipeline(s) for all pipeline receipts of NGLs; 

by manifests for deliveries made to trucks or rail cars; or 
391

metered quantities accepted by the entities purchasing the 

output from the fractionator whether by pipeline or by 

truck or rail car. In cases where the metered data from 

the receiving pipeline(s) or purchasing entities are not 

available, fractionators may substitute estimates based on 

contract quantities required to be delivered under purchase 

or delivery contracts with other parties. 

(2) LDCs shall either substitute their delivering 

pipeline metered deliveries at the city gate or substitute 

nominations and scheduled delivery quantities for the 

period when metered values of actual deliveries are not 

available. 

(c) Determination of HHV and EF. 

(1) Whenever an LDC that makes its own HHV 

measurements according to established business practices 

cannot follow the quality assurance procedures for 

developing a reporter-specific HHV, as specified in 

§98.404, during any period for any reason, the reporter 

shall use either its delivering pipeline measurements or 

the default HHV provided in Table NN-1 of this part for 

that period. 

(2) Whenever an LDC that does not make its own HHV 

measurements according to established business practices or 

an NGL fractionator cannot follow the quality assurance 
392

procedures for developing a reporter-specific HHV, as 

specified in §98.404, during any period for any reason, the 

reporter shall use the default HHV provided in Table NN-1 

of this part for that period. 

(3) Whenever a NGL fractionator cannot follow the 

quality assurance procedures for developing a reporterspecific HHV, as specified in §98.404, during any period 

for any reason, the NGL fractionator shall use the default 

HHV provided in Table NN-1 of this part for that period. 

(4) Whenever a reporter cannot follow the quality 

assurance procedures for developing a reporter-specific EF, 

as specified in §98.404, during any period for any reason, 

the reporter shall use the default EF provided in §98.408 

for that period. 

§98.406 Data reporting requirements. 

(a) In addition to the information required by 

§98.3(c), the annual report for each NGL fractionator 

covered by this rule shall contain the following 

information. 

(1) Annual quantity (in barrels) of each NGL product 

supplied to downstream facilities in the following product 

categories: ethane, propane, normal butane, isobutane, and 

pentanes plus. 
393

(2) Annual quantity (in barrels) of each NGL product 

received from other NGL fractionators in the following 

product categories: ethane, propane, normal butane, 

isobutane, and pentanes plus. 

(3) Annual volumes in Mscf of natural gas received 

for processing. 

(4) Annual quantity (in barrels) of y-grade, bulk 

NGLs received from others for fractionation. 

(5) Annual quantity (in barrels) of propane that the 

NGL fractionator odorizes at the facility and delivers to 

others. 

(6) Annual CO2 emissions (metric tons) that would 

result from the complete combustion or oxidation of the 

quantities in paragraphs (a)(1) and (a)(2) of this section, 

calculated in accordance with §98.403(a) and (c)(1). 

(7) Annual CO2 mass emissions (metric tons) that would 

result from the combustion or oxidation of fractionated 

NGLs supplied less the quantity received by other 

fractionators, calculated in accordance with §98.403(c)(2). 

(8) The specific industry standard used to measure 

each quantity reported in paragraph (a)(1) of this section. 

(9) If the NGL fractionator developed reporterspecific EFs or HHVs, report the following for each product 

type: 

Deleted: b

Deleted: b

Deleted: LNG
394

(i) The specific industry standard(s) used to develop 

reporter-specific higher heating value(s) and/or emission 

factor(s), pursuant to §98.404 (b)(2) and (c)(3). 

(ii) The developed HHV(s). 

(iii) The developed EF(s). 

(b) In addition to the information required by 

§98.3(c), the annual report for each LDC shall contain the 

following information. 

(1) Annual volume in Mscf of natural gas received by 

the LDC at its city gate stations for redelivery on the 

LDC’s distribution system, including for use by the LDC. 

(2) Annual volume in Mscf of natural gas placed into 

storage. 

(3) Annual volume in Mscf of vaporized liquefied 

natural gas (LNG) produced at on-system vaporization 

facilities for delivery on the distribution system that is 

not accounted for in paragraph (b)(1) of this section. 

(4) Annual volume in Mscf of natural gas withdrawn 

from on-system storage (that is not delivered to the city 

gate) for delivery on the distribution system. 

(5) Annual volume in Mscf of natural gas delivered 

directly to LDC systems from producers or natural gas 

processing plants from local production. 
395

(6) Annual volume in Mscf of natural gas delivered to 

downstream gas transmission pipelines and other local 

distribution companies. 

(7) Annual volume in Mscf of natural gas delivered by 

LDC to each meter registering supply equal to or greater 

than 460,000 Mcsf during the calendar year. 

(8) The total annual CO2 mass emissions (metric tons) 

associated with the volumes in paragraphs (b)(1) through 

(b)(7) of this section, calculated in accordance with 

§98.403(a) and (b)(1) through (b)(3). 

(9) Annual CO2 emissions (metric tons) that would 

result from the complete combustion or oxidation of the 

annual supply of natural gas to end-users registering less 

than 460,000 Mcsf, calculated in accordance with 

§98.403(b)(4). 

(10) The specific industry standard used to develop 

the volume reported in paragraph (b)(1) of this section. 

(11) If the LDC developed reporter-specific EFs or 

HHVs, report the following: 

(i) The specific industry standard(s) used to develop 

reporter-specific higher heating value(s) and/or emission 

factor(s), pursuant to §98.404 (b)(2) and (c)(3). 

(ii) The developed HHV(s). 

(iii) The developed EF(s). 
396

(12) The customer name, address, and meter number of 

each meter reading used to report in paragraph (b)(7) of 

this section. 

(i) If known, report the EIA identification number of 

each LDC customer. 

(ii) [Reserved] 

(13) The annual volume in Mscf of natural gas 

delivered by the local distribution company to each of the 

following end-use categories. For definitions of these 

categories, refer to EIA Form 176 (Annual Report of Natural 

Gas and Supplemental Gas Supply & Disposition) and 

Instructions. 

(i) Residential consumers. 

(ii) Commercial consumers. 

(iii) Industrial consumers. 

(iv) Electricity generating facilities. 

(c) Each reporter shall report the number of days in 

the reporting year for which substitute data procedures 

were used for the following purpose: 

(1) To measure quantity. 

(2) To develop HHV(s). 

(3) To develop EF(s). 

§98.407 Records that must be retained.
397

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

each annual report must contain the following information: 

(a) Records of all meter readings and documentation 

to support volumes of natural gas and NGLs that are 

reported under this part. 

(b) Records documenting any estimates of missing 

metered data and showing the calculations of the values 

used for the missing data. 

(c) Calculations and worksheets used to estimate CO2

emissions for the volumes reported under this part. 

(d) Records related to the large end-users identified 

in §98.406(b)(7). 

(e) Records relating to measured Btu content or 

carbon content showing specific industry standards used to 

develop reporter-specific higher heating values and 

emission factors. 

(f) Records of such audits as required by Sarbanes 

Oxley regulations on the accuracy of measurements of 

volumes of natural gas and NGLs delivered to customers or 

on behalf of customers. 

§98.408 Definitions.

All terms used in this subpart have the same meaning 

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

Deleted: daily 

Deleted: 6
398

Table NN-1 of Subpart NN—Default Factors for Calculation 

Methodology 1 of this Subpart 

Fuel Default High Heating 

Value Factor

Default CO2 Emission 

Factor (kg CO2 /MMBtu) 

Natural Gas 1.028 MMBtu/Mscf 53.02 

Propane 3.822 MMBtu/bbl 61.46

Normal butane 4.242 MMBtu/bbl 65.15

Ethane 4.032 MMBtu/bbl 62.64

Isobutane 4.074 MMBtu/bbl 64.91

Pentanes plus 4.620 MMBtu/bbl 70.02

Table NN-2 of Subpart NN—Lookup Default Values for 

Calculation Methodology 2 of this Subpart 

Fuel Unit 

Default CO2 Emission 

Value 

(MT CO2/Unit) 

Natural Gas Mscf 0.055

Propane Barrel 0.235

Normal butane Barrel 0.276

Ethane Barrel 0.253

Isobutane Barrel 0.266

Pentanes plus Barrel 0.324

Deleted: 7

Deleted: 36

Deleted: 3.02

Deleted: 326

Deleted: 4.93

Deleted: 3.082

Deleted: 59.58

Deleted: 3.974

Deleted: 5.08

Deleted: 66.90

Deleted: 41745

Deleted: 80887

Deleted: 183626

Deleted: 58628

Deleted: 09078
Page 325: [1] Deleted Author 

L0 (Equivalent to DOC = 

0.2028 when MCF=1, 

DOCF=0.5, and F=0.5) 

0.067 metric tons CH4/ metric 

ton waste 

Page 326: [2] Deleted Author 

1950 0.63 

1951 0.63 

1952 0.63 

1953 0.63 

1954 0.63 

1955 0.63 

1956 0.63 

1957 0.63 

1958 0.63 

1959 0.63 

Page 326: [3] Deleted Author 

1950 0.63 

1951 0.63 

1952 0.63 

1953 0.63 

1954 0.63 

1955 0.63 

1956 0.63 

1957 0.63 

1958 0.63 

1959 0.63