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Subpart A—General Provision

§ 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 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 this subpart 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 

applicable subpart shall take precedence.

(c) For facilities required to report under onshore petroleum and natural gas production 

under subpart W of this part, the terms Owner and Operator used in subpart A have the same 

definition as Onshore petroleum and natural gas production owner or operator, as defined in § 

98.238 of this part.

§ 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 or under or attached to the Outer Continental Shelf (as defined in 43 

U.S.C. 1331) 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:

(1) A facility that contains any source category that is listed in Table A-3 of this subpart.

For these facilities, the annual GHG report must cover stationary fuel combustion sources 
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(subpart C of this part), miscellaneous use of carbonates (subpart U of this part), and all 

applicable source categories listed in Table A-3 and Table A-4 of this subpart.

(2) A facility that contains any source category that is listed in Table A-4 of this subpart 

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 applicable source categories that 

are listed in Table A-3 and Table A-4 of this subpart. For these facilities, the annual GHG report 

must cover stationary fuel combustion sources (subpart C of this part), miscellaneous use of 

carbonates (subpart U of this part), and all applicable source categories listed in Table A-3 and 

Table A-4 of this subpart.

(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 that is listed in Table A-5 of this subpart. For these suppliers, the annual 

GHG report must cover all applicable products for which calculation methodologies are provided 

in the subparts listed in Table A-5 of this subpart.

(5) Research and development activities are not considered to be part of any source 

category defined in this part.
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(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.

(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.

(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.

Where:

CO2e = Carbon dioxide equivalent, metric tons/year.

GHGi = Mass emissions of each greenhouse gas, 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.
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(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) 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 products that are imported during the 

reporting year and, that are exported during the reporting year. Compare the imported quantities 

and the exported quantities separately to the 25,000 metric ton CO2 per year threshold. Calculate 

the quantities 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) of this 

section, calculate the mass in metric tons per year of CO2 that would result from the complete 

combustion or oxidation of the combined volume of petroleum products and natural gas liquids 

that are imported during the reporting year and that are exported during the reporting year. 

Compare the imported quantities and the exported quantities separately to the 25,000 metric ton 

CO2 per year threshold. Calculate the quantities using the methodology specified in subpart MM 

of this part.
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(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. Compare the imported quantities and the exported quantities 

separately to the 25,000 metric ton CO2 per year threshold.

(1) Calculate the mass in metric tons per year of CO2, N2O, and each fluorinated GHG 

that is imported and the mass in metric tons per year of CO2, N2O, and each fluorinated GHG 

that is exported during the year. 

(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, if a facility or supplier exceeds the 

applicability requirements of paragraph (a) of this section at a later time pursuant to § 98.3(b)(3). 

Thus, the owner or operator should reevaluate the applicability to this part (including the revising 

of any relevant emissions calculations or other calculations) whenever there is any change that 
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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 year. The owner or operator must maintain the 

corresponding records required under § 98.3(g) for each of the five consecutive years prior to 

notification of discontinuation of reporting 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 
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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 prior to notification of discontinuation of reporting 

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.

(3) If the operations of a facility or supplier are changed such that all applicable processes 

and operations subject to paragraphs (a)(1) through (4) of this section cease to operate, then the 

owner or operator may discontinue complying with this part for the reporting 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 applicable processes and operations no later than March 31 of the year

following such changes. If one or more processes or operations subject to paragraphs (a)(1) 

through (4) of this section at a facility or supplier cease to operate, but not all applicable 

processes or operations cease to operate, then the owner or operator is exempt from reporting for 

any such processes or operations in the reporting years following the reporting year in which 

cessation of the process or operation occurs, provided that the owner or operator submits a 

notification to the Administrator that announces the cessation of reporting for the process or 

operation no later than March 31 of the year following such changes. This paragraph (i)(3) does 

not apply to seasonal or other temporary cessation of operations. This paragraph (i)(3) does not 

apply to facilities with municipal solid waste landfills or industrial waste landfills, or to 

underground coal mines except those with abandoned status as determined by the U.S. Mine 
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Safety & Health Administration. The owner or operator must resume reporting for any future 

calendar year during which any of the GHG-emitting processes or operations resume operation.

(4) The provisions of paragraphs (i)(1) and (2) of this section apply to suppliers subject to 

subparts LL through QQ of this part by substituting the term "quantity of GHG supplied" for 

"emissions." For suppliers, the provisions of paragraphs (i)(1) and (2) of this section apply

individually to each importer and exporter and individually to each petroleum refinery, 

fractionator of natural gas liquids, local natural gas distribution company, and producer of CO2, 

N2O, or fluorinated greenhouse gases (e.g., a supplier of industrial greenhouse gases might 

qualify to discontinue reporting as an exporter of industrial greenhouse gases but still be required 

to report as an importer; or a company might qualify to discontinue reporting as a supplier of 

industrial greenhouse gases under subpart OO but still be required to report as a supplier of 

carbon dioxide under subpart PP).

(5) If the operations of a facility or supplier are changed such that a process or operation 

no longer meets the "Definition of Source Category" as specified in an applicable subpart, then 

the owner or operator may discontinue complying with any such subpart for the reporting years 

following the year in which change occurs, provided that the owner or operator submits a 

notification to the Administrator that announces the cessation of reporting for the process or 

operation no later than March 31 of the year following such changes. The owner or operator 

must resume complying with this part for the process or operation starting in any future calendar 

year during which the process or operation meets the "Definition of Source Category" as 

specified in an applicable subpart.

(6) If an entire facility or supplier is merged into another facility or supplier that is 

already reporting GHG data under this part, then the owner or operator may discontinue 
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complying with this part for the facility or supplier, provided that the owner or operator submits 

a notification to the Administrator that announces the discontinuation of reporting and the eGGRT identification number of the reconstituted facility no later than March 31 of the year 

following such changes.

(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.

(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 for reporting year 2010 must be submitted no later 

than September 30, 2011. The annual report for reporting years 2011 and beyond must be 

submitted no later than March 31 of each calendar year for GHG emissions in the previous 

calendar year, except as provided in paragraph (b)(1) of this section.

(1) For reporting year 2011, facilities with one or more of the subparts listed in 

paragraphs (b)(1)(i) through (b)(1)(xi) of this section and suppliers listed in paragraph (b)(1)(xii) 

of this section are required to submit their annual GHG report no later than September 28, 2012. 

Facilities and suppliers that are submitting their second annual GHG report in 2012 and that are 

reporting on one or more subparts listed in paragraphs (b)(1)(i) through (b)(1)(xii) of this section 
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must notify EPA by March 31, 2012 that they are not required to submit their annual GHG report 

until September 28, 2012.

(i) Electronics Manufacturing (subpart I).

(ii) Fluorinated Gas Production (subpart L).

(iii) Magnesium Production (subpart T).

(iv) Petroleum and Natural Gas Systems (subpart W).

(v) Use of Electric Transmission and Distribution Equipment (subpart DD).

(vi) Underground Coal Mines (subpart FF).

(vii) Industrial Wastewater Treatment (subpart II).

(viii) Geologic Sequestration of Carbon Dioxide (subpart RR).

(ix) Manufacture of Electric Transmission and Distribution (subpart SS).

(x) Industrial Waste Landfills (subpart TT).

(xi) Injection of Carbon Dioxide (subpart UU).

(xii) Imports and Exports of Equipment Pre-charged with Fluorinated GHGs or 

Containing Fluorinated GHGs in Closed-cell Foams (subpart QQ).

(2) For a new facility or supplier that begins operation on or after January 1, 2010 and 

becomes subject to the rule in the year that it becomes operational, 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 
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December 31 of that year. For a facility or supplier that becomes subject to this rule solely 

because of an increase 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.

(4) Unless otherwise stated, if the final day of any time period falls on a weekend or a 

federal holiday, the time period shall be extended to the next business day.

(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 of the 

facility or supplier, including the city, State, and zip code. If the facility does not have a physical 

street address, then the facility must provide the latitude and longitude representing the 

geographic centroid or center point of facility operations in decimal degree format. This must be 

provided in a comma-delimited “latitude, longitude” coordinate pair reported in decimal degrees 

to at least four digits to the right of the decimal point.

(2) Year and months covered by the report.

(3) Date of submittal.

(4) For facilities, except as otherwise provided in paragraph (c)(12) of this section, report 

annual emissions of CO2, CH4, N2O, each fluorinated GHG (as defined in § 98.6), and each 

fluorinated heat transfer fluid (as defined in § 98.98) as follows.

(i) Annual emissions (excluding biogenic CO2) aggregated for all GHG from all 

applicable source categories, expressed in metric tons of CO2e calculated using Equation A-1 of 
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this subpart. For electronics manufacturing (as defined in § 98.90), starting in reporting year 

2012 the CO2e calculation must include each fluorinated heat transfer fluid (as defined in § 

98.98) whether or not it is also a fluorinated GHG.

(ii) Annual emissions of biogenic CO2 aggregated for all applicable source categories, 

expressed in metric tons.

(iii) Annual emissions from each applicable source category, expressed in metric tons of 

each applicable GHG listed in paragraphs (c)(4)(iii)(A) through (c)(4)(iii)(F) of this section.

(A) Biogenic CO2.

(B) CO2 (excluding biogenic CO2).

(C) CH4.

(D) N2O.

(E) Each fluorinated GHG (as defined in § 98.6), except fluorinated gas production 

facilities must comply with § 98.126(a) rather than this paragraph (c)(4)(iii)(E). If a fluorinated 

GHG does not have a chemical-specific GWP in Table A-1 of this subpart, identify and report 

the fluorinated GHG group of which that fluorinated GHG is a member.

(F) For electronics manufacturing (as defined in § 98.90), each fluorinated heat transfer 

fluid (as defined in § 98.98) that is not also a fluorinated GHG as specified under (c)(4)(iii)(E) of 

this section. If a fluorinated heat transfer fluid does not have a chemical-specific GWP in Table 

A-1 of this subpart, identify and report the fluorinated GHG group of which that fluorinated heat 

transfer fluid is a member.

(G) For each reported fluorinated GHG and fluorinated heat transfer fluid, report the 

following identifying information:
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(1) Chemical name. If the chemical is not listed in Table A-1 of this subpart, then use the 

method of naming organic chemical compounds as recommended by the International Union of 

Pure and Applied Chemistry (IUPAC). 

(2) The CAS registry number assigned by the Chemical Abstracts Registry Service. If a 

CAS registry number is not assigned or is not associated with a single fluorinated GHG or 

fluorinated heat transfer fluid, then report an identification number assigned by EPA’s Substance 

Registry Services.

(3) Linear chemical formula.

(iv) Except as provided in paragraph (c)(4)(vii) of this section, 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.

(v) Indicate (yes or no) whether reported emissions include emissions from a 

cogeneration unit located at the facility.

(vi) [Reserved]

(vii) The owner or operator of a facility is not required to report the data elements 

specified in Table A-6 of this subpart for calendar years 2010 through 2011 until March 31, 

2013. The owner or operator of a facility is not required to report the data elements specified in 

Table A-7 of this subpart for calendar years 2010 through 2013 until March 31, 2015 (as part of 

the annual report for reporting year 2014), except as otherwise specified in Table A-7 of this 

subpart.

(viii) Applicable source categories means stationary fuel combustion sources (subpart C 

of this part), miscellaneous use of carbonates (subpart U of this part), and all of the source 

categories listed in Table A-3 and Table A-4 of this subpart present at the facility.
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(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 Table A-5 of this subpart 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 Table A-5 to this 

subpart, expressed in metric tons of each GHG. For each reported fluorinated GHG, report the 

following identifying information:

(A) Chemical name. If the chemical is not listed in Table A-1 of this subpart, then use the 

method of naming organic chemical compounds as recommended by the International Union of 

Pure and Applied Chemistry (IUPAC). 

(B) The CAS registry number assigned by the Chemical Abstracts Registry Service. If a 

CAS registry number is not assigned or is not associated with a single fluorinated GHG, then 

report an identification number assigned by EPA’s Substance Registry Services.

(C) Linear chemical formula.

(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, the parameter 

measured using the method, and the time period during which the “best available monitoring 

method” was used, if applicable.
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(8) Each parameter 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 parameter. Parameters include not only reported data elements, but 

any data element required for monitoring and calculating emissions.

(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).

(10) NAICS code(s) that apply to the facility or supplier.

(i) Primary NAICS code. Report the NAICS code that most accurately describes the 

facility or supplier's primary product/activity/service. The primary product/activity/service is the 

principal source of revenue for the facility or supplier. A facility or supplier that has two distinct 

products/activities/services providing comparable revenue may report a second primary NAICS 

code.

(ii) Additional NAICS code(s). Report all additional NAICS codes that describe all 

product(s)/activity(s)/service(s) at the facility or supplier that are not related to the principal 

source of revenue.

(11) Legal name(s) and physical address(es) of the highest-level United States parent 

company(s) of the owners (or operators) of the facility or supplier and the percentage of 

ownership interest for each listed parent company as of December 31 of the year for which data 

are being reported according to the following instructions:

(i) If the facility or supplier is entirely owned by a single United States company that is 

not owned by another company, provide that company's legal name and physical address as the 

United States parent company and report 100 percent ownership.
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(ii) If the facility or supplier is entirely owned by a single United States company that is, 

itself, owned by another company (e.g., it is a division or subsidiary of a higher-level company), 

provide the legal name and physical address of the highest-level company in the ownership 

hierarchy as the United States parent company and report 100 percent ownership.

(iii) If the facility or supplier is owned by more than one United States company (e.g.,

company A owns 40 percent, company B owns 35 percent, and company C owns 25 percent), 

provide the legal names and physical addresses of all the highest-level companies with an 

ownership interest as the United States parent companies, and report the percent ownership of 

each company.

(iv) If the facility or supplier is owned by a joint venture or a cooperative, the joint 

venture or cooperative is its own United States parent company. Provide the legal name and 

physical address of the joint venture or cooperative as the United States parent company, and 

report 100 percent ownership by the joint venture or cooperative.

(v) If the facility or supplier is entirely owned by a foreign company, provide the legal 

name and physical address of the foreign company's highest-level company based in the United 

States as the United States parent company, and report 100 percent ownership.

(vi) If the facility or supplier is partially owned by a foreign company and partially

owned by one or more U.S. companies, provide the legal name and physical address of the 

foreign company's highest-level company based in the United States, along with the legal names 

and physical addresses of the other U.S. parent companies, and report the percent ownership of 

each of these companies.

(vii) If the facility or supplier is a federally owned facility, report “U.S. Government” and 

do not report physical address or percent ownership.
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(viii) The facility or supplier must refer to the reporting instructions of the electronic 

GHG reporting tool regarding standardized conventions for the naming of a parent company.

(12) For the 2010 reporting year only, facilities that have “part 75 units” (i.e. units that 

are subject to subpart D of this part or units that use the methods in part 75 of this chapter to 

quantify CO2 mass emissions in accordance with § 98.33(a)(5)) must report annual GHG 

emissions either in full accordance with paragraphs (c)(4)(i) through (c)(4)(iii) of this section or 

in full accordance with paragraphs (c)(12)(i) through (c)(12)(iii) of this section. If the latter 

reporting option is chosen, you must report:

(i) Annual emissions aggregated for all GHG from all applicable source categories, 

expressed in metric tons of CO2e calculated using Equation A-1 of this subpart. You must 

include biogenic CO2 emissions from part 75 units in these annual emissions, but exclude 

biogenic CO2 emissions from any non-part 75 units and other source categories.

(ii) Annual emissions of biogenic CO2, expressed in metric tons (excluding biogenic CO2

emissions from part 75 units), aggregated for all applicable source categories.

(iii) Annual emissions from each applicable source category, expressed in metric tons of 

each applicable GHG listed in paragraphs (c)(12)(iii)(A) through (c)(12)(iii)(E) of this section.

(A) Biogenic CO2 (excluding biogenic CO2 emissions from part 75 units).

(B) CO2. You must include biogenic CO2 emissions from part 75 units in these totals and 

exclude biogenic CO2 emissions from other non-part 75 units and other source categories.

(C) CH4.

(D) N2O.

(E) Each fluorinated GHG (including those not listed in Table A-1 of this subpart).
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(13) An indication of whether the facility includes one or more plant sites that have been 

assigned a “plant code” (as defined under § 98.6) by either the Department of Energy's Energy

Information Administration or by the EPA's Clean Air Markets Division.

(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:

(i) Monitoring methods currently used by the facility that do not meet the specifications 

of a 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.
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(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.

(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.
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(F) A description of the specific actions the facility will take to obtain and install the 

equipment as 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 September 30, 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 2012. 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.

(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) For each stationary fuel combustion source that meets the criteria specified in § 

98.36(f), report any facility operating data or process information used for the GHG emission 
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calculations. A stationary fuel combustion source that does not meet the criteria specified in §

98.36(f) must either report the data specified in this paragraph (d)(3)(v) in the annual report or 

use verification software according to § 98.5(b) in lieu of reporting the data specified in this 

paragraph.

(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)(9) 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 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 (g). Except as otherwise provided in this 

paragraph, retain all required records for at least 3 years from the date of submission of the 

annual GHG report for the reporting year in which the record was generated. 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. If the owner or operator of a facility is required 
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under § 98.5(b) to use verification software specified by the Administrator, then all records 

required for the facility under this part must be retained for at least 5 years from the date of 

submission of the annual GHG report for the reporting year in which the record was generated, 

starting with records for reporting year 2010. 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 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. For data required by § 98.5(b) to 

be entered into verification software specified in § 98.5(b), maintain the entered data in the 

format generated by the verification software according to § 98.5(b).

(ii) Analytical results for the development of site-specific 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.
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(3) The annual GHG reports.

(4) Missing data computations. For each missing data event, also retain a record of the 

cause of the event and the corrective actions taken to restore malfunctioning monitoring 

equipment.

(5) A written GHG Monitoring Plan.

(i) At a minimum, the GHG Monitoring Plan shall include the elements listed in this 

paragraph (g)(5)(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.

(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 maintenance and repair of monitoring systems to reduce the 

frequency of monitoring equipment downtime.
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(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.

(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. (1) The owner or operator shall submit a revised 

annual GHG report within 45 days of discovering that an annual GHG report that the owner or 

operator previously submitted contains one or more substantive errors. The revised report must 

correct all substantive errors.

(2) The Administrator may notify the owner or operator in writing that an annual GHG 

report previously submitted by the owner or operator contains one or more substantive errors. 

Such notification will identify each such substantive error. The owner or operator shall, within 

45 days of receipt of the notification, either resubmit the report that, for each identified 

substantive error, corrects the identified substantive error (in accordance with the applicable 

requirements of this part) or provide information demonstrating that the previously submitted 

report does not contain the identified substantive error or that the identified error is not a 

substantive error.

(3) A substantive error is an error that impacts the quantity of GHG emissions reported or 

otherwise prevents the reported data from being validated or verified.
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(4) Notwithstanding paragraphs (h)(1) and (2) of this section, upon request by the owner 

or operator, the Administrator may provide reasonable extensions of the 45-day period for 

submission of the revised report or information under paragraphs (h)(1) and (2) of this section. If 

the Administrator receives a request for extension of the 45-day period, by email to an address 

prescribed by the Administrator prior to the expiration of the 45-day period, the extension 

request is deemed to be automatically granted for 30 days. The Administrator may grant an 

additional extension beyond the automatic 30-day extension if the owner or operator submits a 

request for an additional extension and the request is received by the Administrator prior to the 

expiration of the automatic 30-day extension, provided the request demonstrates that it is not 

practicable to submit a revised report or information under paragraphs (h)(1) and (2) within 75 

days. The Administrator will approve the extension request if the request demonstrates to the 

Administrator's satisfaction that it is not practicable to collect and process the data needed to 

resolve potential reporting errors identified pursuant to paragraphs (h)(1) or (2) of this section 

within 75 days.

(5) The owner or operator shall retain documentation for 3 years to support any revision 

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 applicable flow meter calibration and 

accuracy requirements of this paragraph (i). The accuracy specifications in this paragraph (i) do 

not apply where either the use of company records (as defined in § 98.6) or the use of “best 

available information” is specified in an applicable subpart of this part to quantify fuel usage 

and/or other parameters. Further, the provisions of this paragraph (i) do not apply to stationary
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fuel combustion units that use the methodologies in part 75 of this chapter to calculate CO2 mass 

emissions.

(1) Except as otherwise provided in paragraphs (i)(4) through (i)(6) of this section, flow 

meters that measure liquid and gaseous fuel feed rates, process stream flow rates, or feedstock 

flow rates and provide data for the GHG emissions calculations shall be calibrated prior to April 

1, 2010 using the procedures specified in this paragraph (i) when such calibration is specified in 

a relevant subpart of this part. Each of these flow meters shall meet the applicable accuracy

specification in paragraph (i)(2) or (i)(3) of this section. All other measurement devices (e.g.,

weighing devices) that are required by a relevant subpart of this part, and that are used to provide 

data for the GHG emissions calculations, shall also be calibrated prior to April 1, 2010; however, 

the accuracy specifications in paragraphs (i)(2) and (i)(3) of this section do not apply to these 

devices. Rather, each of these measurement devices shall be calibrated to meet the accuracy

requirement specified for the device in the applicable subpart of this part, or, in the absence of 

such accuracy requirement, the device must be calibrated to an accuracy within the appropriate 

error range for the specific measurement technology, based on an applicable operating standard, 

including but not limited to manufacturer's specifications and industry standards. The procedures 

and methods used to quality-assure the data from each measurement device shall be documented 

in the written monitoring plan, pursuant to paragraph (g)(5)(i)(C) of this section.

(i) All flow meters and other measurement devices that are subject to the provisions of 

this paragraph (i) must be calibrated according to one of the following: You may use the 

manufacturer's recommended procedures; an appropriate industry consensus standard method; or 

a method specified in a relevant subpart of this part. The calibration method(s) used shall be 

documented in the monitoring plan required under paragraph (g) of this section.
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(ii) For facilities and suppliers that become subject to this part after April 1, 2010, all 

flow meters and other measurement devices (if any) that are required by the relevant subpart(s) 

of this part to provide data for the GHG emissions calculations shall be installed no later than the 

date on which data collection is required to begin using the measurement device, and the initial 

calibration(s) required by this paragraph (i) (if any) shall be performed no later than that date.

(iii) Except as otherwise provided in paragraphs (i)(4) through (i)(6) of this section, 

subsequent recalibrations of the flow meters and other measurement devices subject to the 

requirements of this paragraph (i) shall be performed at one of the following frequencies:

(A) You may use the frequency specified in each applicable subpart of this part.

(B) You may use the frequency recommended by the manufacturer or by an industry 

consensus standard practice, if no recalibration frequency is specified in an applicable subpart.

(2) Perform all flow meter calibration at measurement points that are representative of the 

normal operating range 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.

where:

CE = Calibration error (%).

R = Reference value.

A = Flow meter response to the reference value.
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(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.

(i) 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 6.0 percent.

where:

CE = Calibration error (%).

R = Reference value.

A = Transmitter response to the reference value.

FS = Full-scale value of the transmitter.

(ii) In cases where there are only two transmitters (i.e., differential pressure and either 

temperature or total pressure) in the immediate vicinity of the flow meter's primary element (e.g.,

the orifice plate), or when there is only a differential pressure transmitter in close proximity to 

the primary element, calibration of these existing transmitters to a CE of 2.0 percent or less at 

each measurement point is still required, in accordance with paragraph (i)(3)(i) of this section; 
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alternatively, when two transmitters are calibrated, the results are acceptable if the sum of the CE 

values for the two transmitters at each calibration level does not exceed 4.0 percent. However, 

note that installation and calibration of an additional transmitter (or transmitters) at the flow 

monitor location to measure temperature or total pressure or both is not required in these cases. 

Instead, you may use assumed values for temperature and/or total pressure, based on 

measurements of these parameters at a remote location (or locations), provided that the following 

conditions are met:

(A) You must demonstrate that measurements at the remote location(s) can, when 

appropriate correction factors are applied, reliably and accurately represent the actual 

temperature or total pressure at the flow meter under all expected ambient conditions.

(B) You must make all temperature and/or total pressure measurements in the 

demonstration described in paragraph (i)(3)(ii)(A) of this section with calibrated gauges, sensors, 

transmitters, or other appropriate measurement devices. At a minimum, calibrate each of these 

devices to an accuracy within the appropriate error range for the specific measurement 

technology, according to one of the following. You may calibrate using a manufacturer's 

specification or an industry consensus standard.

(C) You must document the methods used for the demonstration described in paragraph 

(i)(3)(ii)(A) of this section in the written GHG Monitoring Plan under paragraph (g)(5)(i)(C) of 

this section. You must also include the data from the demonstration, the mathematical 

correlation(s) between the remote readings and actual flow meter conditions derived from the 

data, and any supporting engineering calculations in the GHG Monitoring Plan. You must 

maintain all of this information in a format suitable for auditing and inspection.
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(D) You must use the mathematical correlation(s) derived from the demonstration 

described in paragraph (i)(3)(ii)(A) of this section to convert the remote temperature or the total 

pressure readings, or both, to the actual temperature or total pressure at the flow meter, or both, 

on a daily basis. You shall then use the actual temperature and total pressure values to correct the 

measured flow rates to standard conditions.

(E) You shall periodically check the correlation(s) between the remote and actual 

readings (at least once a year), and make any necessary adjustments to the mathematical 

relationship(s).

(4) Fuel billing meters are exempted from the calibration requirements of this section and 

from the GHG Monitoring Plan and recordkeeping provisions of paragraphs (g)(5)(i)(C), (g)(6), 

and (g)(7) 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. 

Meters used exclusively to measure the flow rates of fuels that are used for unit startup are also 

exempted from the calibration requirements of this section.

(5) For a flow meter that has been previously calibrated in accordance with paragraph 

(i)(1) of this section, an additional calibration is not required by the date specified in paragraph 

(i)(1) of this section if, as of that date, the previous calibration is still active (i.e., the device is not 

yet due for recalibration because the time interval between successive calibrations has not

elapsed). In this case, the deadline for the successive calibrations of the flow meter shall be set 

according to one of the following. You may use either the manufacturer's recommended 

calibration schedule or you may use the industry consensus calibration schedule.

(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 
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measurement device without disrupting normal process operation. In such cases, the owner or 

operator may postpone the initial calibration until the next scheduled maintenance outage. The 

best available information from company records may be used in the interim. The subsequent 

required recalibrations of the flow meters may be similarly postponed. Such postponements shall 

be documented in the monitoring plan that is required under paragraph (g)(5) of this section.

(7) If the results of an initial calibration or a recalibration fail to meet the required 

accuracy specification, data from the flow meter shall be considered invalid, beginning with the 

hour of the failed calibration and continuing until a successful calibration is completed. You 

shall follow the missing data provisions provided in the relevant missing data sections during the 

period of data invalidation.

(j) Measurement device installation—(1) General. If an owner or operator required to 

report under subpart P, subpart X or subpart Y of this part has process equipment or units that 

operate continuously and it is not possible to install a required flow meter or other measurement 

device by April 1, 2010, (or by any later date in 2010 approved by the Administrator as part of 

an extension of best available monitoring methods per paragraph (d) of this section) without 

process equipment or unit shutdown, or through a hot tap, the owner or operator may request an 

extension from the Administrator to delay installing the measurement device until the next 

scheduled process equipment or unit shutdown. If approval for such an extension is granted by

the Administrator, the owner or operator must use best available monitoring methods during the 

extension period.

(2) Requests for extension of the use of best available monitoring methods for 

measurement device installation. The owner or operator must first provide the Administrator an 

initial notification of the intent to submit an extension request for use of best available 
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monitoring methods beyond December 31, 2010 (or an earlier date approved by EPA) in cases 

where measurement device installation would require a process equipment or unit shutdown, or 

could only be done through a hot tap. The owner or operator must follow-up this initial 

notification with the complete extension request containing the information specified in 

paragraph (j)(4) of this section.

(3) Timing of request. (i) The initial notice of intent must be submitted no later than 

January 1, 2011, or by the end of the approved use of best available monitoring methods 

extension in 2010, whichever is earlier. The completed extension request must be submitted to 

the Administrator no later than February 15, 2011.

(ii) Any subsequent extensions to the original request must be submitted to the 

Administrator within 4 weeks of the owner or operator identifying the need to extend the request, 

but in any event no later than 4 weeks before the date for the planned process equipment or unit 

shutdown that was provided in the original or most recently approved request.

(4) Content of the request. Requests must contain the following information:

(i) Specific measurement device for which the request is being made and the location 

where each measurement device will be installed.

(ii) Identification of the specific rule requirements (by rule subpart, section, and 

paragraph numbers) requiring the measurement device.

(iii) A description of the reasons why the needed equipment could not be installed before 

April 1, 2010, or by the expiration date for the use of best available monitoring methods, in cases 

where an extension has been granted under § 98.3(d).

(iv) Supporting documentation showing that it is not practicable to isolate the process 

equipment or unit and install the measurement device without a full shutdown or a hot tap, and 
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that there was no opportunity during 2010 to install the device. Include the date of the three most 

recent shutdowns for each relevant process equipment or unit, the frequency of shutdowns for 

each relevant process equipment or unit, and the date of the next planned process equipment or 

unit shutdown.

(v) Include a description of the proposed best available monitoring method for estimating 

GHG emissions during the time prior to installation of the meter.

(5) Approval criteria. The owner or operator must demonstrate to the Administrator's 

satisfaction that it is not reasonably feasible to install the measurement device before April 1, 

2010 (or by the expiration date for the use of best available monitoring methods, in cases where 

an extension has been granted under paragraph (d) of this section) without a process equipment 

or unit shutdown, or through a hot tap, and that the proposed method for estimating GHG 

emissions during the time before which the measurement device will be installed is appropriate. 

The Administrator will not initially approve the use of the proposed best available monitoring 

method past December 31, 2013.

(6) Measurement device installation deadline. Any owner or operator that submits both a 

timely initial notice of intent and a timely completed extension request under paragraph (j)(3) of 

this section to extend use of best available monitoring methods for measurement device 

installation must install all such devices by July 1, 2011 unless the extension request under this 

paragraph (j) is approved by the Administrator before July 1, 2011.

(7) One time extension past December 31, 2013. If an owner or operator determines that 

a scheduled process equipment or unit shutdown will not occur by December 31, 2013, the 

owner or operator may re-apply to use best available monitoring methods for one additional time 

period, not to extend beyond December 31, 2015. To extend use of best available monitoring 
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methods past December 31, 2013, the owner or operator must submit a new extension request by

June 1, 2013 that contains the information required in paragraph (j)(4) of this section. The owner 

or operator must demonstrate to the Administrator's satisfaction that it continues to not be 

reasonably feasible to install the measurement device before December 31, 2013 without a 

process equipment or unit shutdown, or that installation of the measurement device could only be 

done through a hot tap, and that the proposed method for estimating GHG emissions during the 

time before which the measurement device will be installed is appropriate. An owner or operator 

that submits a request under this paragraph to extend use of best available monitoring methods 

for measurement device installation must install all such devices by December 31, 2013, unless 

the extension request under this paragraph is approved by the Administrator.

(k) Revised global warming potentials and special provisions for reporting year 2013 and 

subsequent reporting years. This paragraph (k) applies to owners or operators of facilities or 

suppliers that first become subject to any subpart of part 98 solely due to an amendment to Table 

A-1 of this subpart.

(1) A facility or supplier that first becomes subject to part 98 due to a change in the GWP 

for one or more compounds in Table A-1 of this subpart, Global Warming Potentials, is not 

required to submit an annual GHG report for the reporting year during which the change in 

GWPs is published.

(2) A facility or supplier that was already subject to one or more subparts of part 98 but 

becomes subject to one or more additional subparts due to a change in the GWP for one or more 

compounds in Table A-1 of this subpart, is not required to include those subparts to which the 

facility is subject only due to the change in the GWP in the annual GHG report submitted for the 

reporting year during which the change in GWPs is published.
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(3) Starting on January 1 of the year after the year during which the change in GWPs is 

published, facilities or suppliers identified in paragraphs (k)(1) or (2) of this section must start 

monitoring and collecting GHG data in compliance with the applicable subparts of part 98 to

which the facility is subject due to the change in the GWP for the annual greenhouse gas report 

for that reporting year, which is due by March 31 of the following calendar year.

(4) A change in the GWP for one or more compounds includes the addition to Table A-1 

of this subpart of either a chemical-specific or a default GWP that applies to a compound to 

which no chemical-specific GWP in Table A-1 of this subpart previously applied.

(l) Special provision for best available monitoring methods in 2014 and subsequent years.

This paragraph (l) applies to owners or operators of facilities or suppliers that first become 

subject to any subpart of part 98 due to an amendment to Table A-1 of this subpart, Global 

Warming Potentials.

(1) Best available monitoring methods. From January 1 to March 31 of the year after the 

year during which the change in GWPs is published, owners or operators subject to this 

paragraph (l) may use best available monitoring methods for any parameter (e.g., fuel use, 

feedstock rates) 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 of the year after the year during which the change in GWPs is published. Starting no 

later than April 1of the year after the year during which the change in GWPs is published, the 

owner or operator must discontinue using best available methods and begin following all 
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applicable monitoring and QA/QC requirements of this part, except as provided in paragraph 

(l)(2) of this section. Best available monitoring methods means any of the following methods:

(i) Monitoring methods currently used by the facility that do not meet the specifications 

of a 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 of the year after the year during which the change in GWPs is 

published.

(i) Timing of request. The extension request must be submitted to EPA no later than 

January 31 of the year after the year during which the change in GWPs is published.

(ii) Content of request. Requests must contain the following information:

(A) A list of specific items 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 that the needed equipment could not be obtained and 

installed before April 1 of the year after the year during which the change in GWPs is published.

(D) If the reason for the extension is that the equipment cannot be purchased and 

delivered by April 1 of the year after the year during which the change in GWPs is published, 

include supporting documentation such as the date the monitoring equipment was ordered, 
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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 November 29 of the year during which the change in GWPs is published and 

April 1 of the year after the year during which the change in GWPs is published, 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 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 of the year after the year during which the 

change in GWPs is published. The use of best available methods under this paragraph (l) will not 

be approved beyond December 31 of the year after the year during which the change in GWPs is 

published.

 

§ 98.4 Authorization and responsibilities of the designated representative.
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(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 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 
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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 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 of this chapter.

(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 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 
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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.

(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.
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(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 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.
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(2) The name, organization name (company affiliation-employer), 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 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.”
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(5) The signature of the designated representative and any alternate designated 

representative and the dates signed.

(6) A list of the subparts that the owners and operators anticipate will be included in the 

annual GHG report. The list of potentially applicable subparts is required only for an initial 

certificate of representation that is submitted after [date of publication of the final rule in the 

Federal Register] (i.e., for a facility or supplier that previously was not registered under this 

part). The list of subparts is not required for a revised COR. 

(j) Documents of agreement. Unless otherwise required by the Administrator, documents 

of agreement 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.
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(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, organization name (company affiliation-employer) address, e-mail address 

(if any), telephone number, and facsimile transmission number (if 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 paragraph (m)(2)(iii) 

of this section, the facility or supplier for which the electronic submission may be made.
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(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 § 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)(v)(A) of 

this section and made in accordance with a notice of delegation effective under paragraph (m)(3) 
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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?

(a) 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.

(b) For reporting year 2014 and thereafter, unless a later year is specified in the 

applicable recordkeeping section, you must enter into verification software specified by the 

Administrator the data specified in the verification software records provision in each applicable 

recordkeeping section. For each data element entered into the verification software, if the 

software produces a warning message for the data value and you elect not to revise the data 

value, you may provide an explanation in the verification software of why the data value is not 

being revised.

 

§ 98.6 Definitions.

All terms used in this part shall have the same meaning given in the Clean Air Act and in 

this section.

Absorbent circulation pump means a pump commonly powered by natural gas pressure 

that circulates the absorbent liquid between the absorbent regenerator and natural gas contactor.

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.
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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.

Administrator means the Administrator of the United States Environmental Protection 

Agency or the Administrator's authorized representative.

AGA means the American Gas Association

Agricultural by-products means those parts of arable crops that are not used for the 

primary purpose of producing food. Agricultural by-products include, but are not limited to, oat, 

corn and wheat straws, bagasse, peanut shells, rice and coconut husks, soybean hulls, palm 

kernel cake, cottonseed and sunflower seed cake, and pomace.

Air injected flare means a flare in which air is blown into the base of a flare stack to 

induce complete combustion of gas.

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, with respect to subpart JJ of this part, means a type of liquid storage 

system component that is designed and operated to stabilize wastes using anaerobic microbial 
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processes. Anaerobic lagoons may be designed for combined stabilization and storage with 

varying lengths of retention time (up to a year or greater), depending on the climate region, 

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 

(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.
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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.

Biomass means non-fossilized and biodegradable organic material originating from 

plants, animals or micro-organisms, 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 non-fossilized 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), 
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reformulated blendstock for oxygenate blending (RBOB), oxygenates (e.g. 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.

Blowdown vent stack emissions mean natural gas and/or CO2 released due to 

maintenance and/or blowdown operations including compressor blowdown and emergency shutdown (ESD) system testing.

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. 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.
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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.

Calibrated bag means a flexible, non-elastic, anti-static bag of a calibrated volume that 

can be affixed to an emitting source such that the emissions inflate the bag to its calibrated 

volume.

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 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.
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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), potassium carbonate (K2CO3), lithium 

carbonate (Li2CO3), and strontium carbonate (SrCO3).

Carbonate-based mineral mass fraction means the following: For limestone, the mass 

fraction of calcium carbonate (CaCO3) in the limestone; for dolomite, the mass fraction of 

calcium magnesium carbonate (CaMg(CO3)2) in the dolomite; for soda ash, the mass fraction of 

sodium carbonate (Na2CO3) in the soda ash; for barium carbonate, the mass fraction of barium 

carbonate (BaCO3) in the barium carbonate; for potassium carbonate, the mass fraction of 

potassium carbonate (K2CO3) in the potassium carbonate; for lithium carbonate, the mass 

fraction of lithium carbonate (Li2CO3); and for strontium carbonate, the mass fraction of 

strontium carbonate (SrCO3).
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Carbonate-based raw material means any of the following materials used in the 

manufacture of glass: Limestone, dolomite, soda ash, barium carbonate, potassium carbonate, 

lithium carbonate, and strontium carbonate.

Carbonofluoridates means fluorinated GHGs that are composed of a -OCF(O) group 

(carbonyl group with a single-bonded oxygen atom and a fluorine atom) that is linked on the 

single-bonded oxygen to another hydrocarbon group in which one or more of the hydrogen 

atoms may be replaced by fluorine atoms.

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, 

catalyst or contact material recovery equipment, and regenerator equipment for controlling air 

pollutant emissions and for heat recovery.

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.
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Cement kiln dust means non-calcined to fully calcined dust produced in the kiln or 

pyroprocessing line. Cement kiln dust is a fine-grained, solid, highly alkaline material removed 

from the cement kiln exhaust gas by scrubbers (filtration baghouses and/or electrostatic 

precipitators).

Centrifugal compressor means any equipment that increases the pressure of a process 

natural gas or CO2 by centrifugal action, employing rotating movement of the driven shaft.

Centrifugal compressor dry seal emissions mean natural gas or CO2 released from a dry

seal vent pipe and/or the seal face around the rotating shaft where it exits one or both ends of the 

compressor case.

Centrifugal compressor dry seals mean a series of rings around the compressor shaft 

where it exits the compressor case that operates mechanically under the opposing forces to 

prevent natural gas or CO2 from escaping to the atmosphere.

Centrifugal compressor wet seal degassing vent emissions means emissions that occur 

when the high-pressure oil barriers for centrifugal compressors are depressurized to release 

absorbed natural gas or CO2. High-pressure oil is used as a barrier against escaping gas in 

centrifugal compressor shafts. Very little gas escapes through the oil barrier, but under high 

pressure, considerably more gas is absorbed by the oil. The seal oil is purged of the absorbed gas 

(using heaters, flash tanks, and degassing techniques) and recirculated. The separated gas is 

commonly vented to the atmosphere.

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.
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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.

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.
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Cogeneration unit means a unit that produces electrical energy and useful thermal energy

for industrial, commercial, or heating or cooling purposes, through the sequential or 

simultaneous use of the original fuel energy.

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 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.
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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 bleed means a continuous flow of pneumatic supply natural gas to the 

process control device (e.g. level control, temperature control, pressure control) where the supply 

gas pressure is modulated by the process condition, and then flows to the valve controller where 

the signal is compared with the process set-point to adjust gas pressure in the valve actuator.

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.

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 
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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 remains liquid at atmospheric pressure after passing through surface 

separating facilities. (1) Depending upon the characteristics of the crude stream, it may also 

include any of the following:

(i) Small amounts of hydrocarbons that exist in gaseous phase in natural underground 

reservoirs but are liquid at atmospheric conditions (temperature and pressure) after being 

recovered from oil well (casing-head) 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.

(ii) Small amounts of non-hydrocarbons, such as sulfur and various metals.

(iii) Drip gases, and liquid hydrocarbons produced from tar sands, oil sands, gilsonite, 

and oil shale.

(iv) Petroleum products that are received or produced at a refinery and subsequently

injected into a crude supply or reservoir by the same refinery owner or operator.

(2) 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.
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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 with the 

primary intent of reducing the carbon content of the steel, including but not limited to vessels 

used for argon-oxygen decarburization and vacuum oxygen decarburization.

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.

Degasification system means the entirety of the equipment that is used to drain gas from 

underground coal mines. This includes all degasification wells and gob gas vent holes at the 

underground coal mine. Degasification systems include gob and premine surface drainage wells, 

gob and premine in-mine drainage wells, and in-mine gob and premine cross-measure borehole 

wells.

Degradable organic carbon (DOC) means the fraction of the total mass of a waste 

material that can be biologically degraded.

Dehydrator means a device in which a liquid absorbent (including desiccant, ethylene 

glycol, diethylene glycol, or triethylene glycol) directly contacts a natural gas stream to absorb 

water vapor.
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Dehydrator vent emissions means natural gas and CO2 released from a natural gas 

dehydrator system absorbent (typically glycol) reboiler or regenerator to the atmosphere or a 

flare, including stripping natural gas and motive natural gas used in absorbent circulation pumps.

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.

De-methanizer means the natural gas processing unit that separates methane rich residue 

gas from the heavier hydrocarbons (e.g., ethane, propane, butane, pentane-plus) in feed natural 

gas stream.

Density means the mass contained in a given unit volume (mass/volume).

Desiccant means a material used in solid-bed dehydrators to remove water from raw 

natural gas by adsorption or absorption. Desiccants include activated alumina, pelletized calcium 

chloride, lithium chloride and granular silica gel material. Wet natural gas is passed through a 

bed of the granular or pelletized solid adsorbent or absorbent in these dehydrators. As the wet 

gas contacts the surface of the particles of desiccant material, water is adsorbed on the surface or 

absorbed and dissolves the surface of these desiccant particles. Passing through the entire 

desiccant bed, almost all of the water is adsorbed onto or absorbed into the desiccant material, 

leaving the dry gas to exit the contactor.

Destruction means:

(1) 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 
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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 off-site use as a fuel.

(2) 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 device, for the purposes of subparts II and TT of this part, 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 or wastewater biogas.

Destruction efficiency means the efficiency with which a destruction device reduces the 

mass of a greenhouse gas fed into the device. Destruction efficiency, or flaring destruction 

efficiency, refers to the fraction of the gas that leaves the flare partially or fully oxidized. The 

destruction efficiency is expressed in Equation A-2 of this section:

where:

DE = Destruction Efficiency

tGHGiIN = The mass of GHG i fed into the destruction device

tGHGiOUT = The mass of GHG i exhausted from the destruction device

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.”
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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, kerosene-type jet fuel, diesel fuels (Diesel Fuels 

No. 1, No. 2, 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.
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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 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 fuel-powered equipment, such as a fire 

pump, that is used only in emergency situations.
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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 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
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installations may classify such 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.

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
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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 generate a low value fuel gas that is used 

as fuel in other combustion sources at the refinery.

Fluorinated acetates means fluorinated GHGs that are composed of an acetate group with 

one or more valence locations on the methyl group of the acetate occupied by fluorine atoms 

(e.g., CFH2C(O)O-, CF2HC(O)O-) and, linked to the single-bonded oxygen of the acetate group, 

another hydrocarbon group in which one or more of the hydrogen atoms may be replaced by 

fluorine atoms.

Fluorinated alcohols other than fluorotelomer alcohols means fluorinated GHGs that 

include an alcohol functional group (-OH) and that do not meet the definition of fluorotelomer 

alcohols.

Fluorinated formates means fluorinated GHGs that are composed of a formate group -

OCH(O) (carbonyl group with a single-bonded oxygen, and with a hydrogen atom) that is linked 

on the single-bonded oxygen atom to a hydrocarbon group in which one or more of the hydrogen 

atoms in the hydrocarbon group is replaced by fluorine atoms; the typical formula for fluorinated 

formates is FnROCH(O).

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 
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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.

Fluorinated greenhouse gas (GHG) group means one of the following sets of fluorinated 

GHGs: Fully fluorinated GHGs; saturated hydrofluorocarbons with 2 or fewer carbon-hydrogen 

bonds; saturated hydrofluorocarbons with 3 or more carbon-hydrogen bonds; saturated 

hydrofluoroethers and hydrochlorofluoroethers with 1 carbon-hydrogen bond; saturated 

hydrofluoroethers and hydrochlorofluoroethers with 2 carbon-hydrogen bonds; saturated 

hydrofluoroethers and hydrochlorofluoroethers with 3 or more carbon-hydrogen bonds; 

fluorinated formates; fluorinated acetates, carbonofluoridates, and fluorinated alcohols other than 

fluorotelomer alcohols; unsaturated PFCs, unsaturated HFCs, unsaturated HCFCs, unsaturated 

halogenated ethers, unsaturated halogenated esters, fluorinated aldehydes, and fluorinated 

ketones; fluorotelomer alcohols; fluorinated GHGs with carbon-iodine bonds; or other 

fluorinated GHGs.

Fluorotelomer alcohols means fluorinated GHGs with the chemical formula 

CnF2n+1CH2CH2OH.

Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous 

fuel derived from such material, for purpose of creating useful heat.

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 further into component products are not considered fractionators. Some 
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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 or petrochemical plant 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.

Fully fluorinated GHGs means fluorinated GHGs that contain only single bonds and in 

which all available valence locations are filled by fluorine atoms. This includes but is not limited 

to: Saturated perfluorocarbons; SF6; NF3; SF5CF3; fully fluorinated linear, branched, and cyclic 

alkanes; fully fluorinated ethers; fully fluorinated tertiary amines; fully fluorinated aminoethers; 

and perfluoropolyethers.

Furnace slag means a by-product formed in metal melting furnaces when slagging agents, 

reducing agents, and/or fluxes (e.g., coke ash, limestone, silicates) are added to remove 

impurities from the molten metal.

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 or similar 

mechanical draft equipment (forced convection) to a single location for treatment (thermal 
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destruction) or use. Landfill gas collection systems may also include knock-out or separator 

drums and/or a compressor. A single landfill may have multiple gas collection systems. Landfill 

gas collection systems do not include “passive” systems, whereby landfill gas flows naturally

(without forced convection) to the surface of the landfill where an opening or pipe (vent) is 

installed to allow for the flow of landfill gas to the atmosphere or to a remote flare installed to 

combust landfill gas that is passively emitted from the vent. Landfill gas collection systems also 

do not include “active venting” systems, whereby landfill gas is conveyed to the surface of the 

landfill using forced convection, but the landfill gas is never recovered or thermally destroyed 

prior to release to the atmosphere.

Gas conditions mean the actual temperature, volume, and pressure of a gas sample.

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.

Gas to oil ratio (GOR) means the ratio of the volume of gas at standard temperature and 

pressure that is produced from a volume of oil when depressurized to standard temperature and 

pressure.

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).
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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). GWPs for each greenhouse gas are provided in Table A-1 

of this subpart. For purposes of the calculations in this part, if the GHG has a chemical-specific 

GWP listed in Table A-1, use that GWP. Otherwise, use the default GWP provided in Table A-1 

for the fluorinated GHG group of which the GHG is a member.

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).

High-bleed pneumatic devices are automated, continuous bleed flow control devices 

powered by pressurized natural gas and used for maintaining a process condition such as liquid 

level, pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by
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the process condition flows to a valve actuator controller where it vents continuously (bleeds) to 

the atmosphere at a rate in excess of 6 standard cubic feet per hour.

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.

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, 
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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 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.

Intermittent bleed pneumatic devices mean automated flow control devices powered by

pressurized natural gas and used for automatically maintaining a process condition such as liquid 

level, pressure, delta-pressure and temperature. These are snap-acting or throttling devices that 

discharge all or a portion of the full volume of the actuator intermittently when control action is 

necessary, but does not bleed continuously.

Isobutane is a paraffinic branch chain hydrocarbon with molecular formula C4H10.
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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.

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.

Liberated means released from coal and surrounding rock strata during the mining 

process. This includes both methane emitted from the ventilation system and methane drained 

from degasification systems.
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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.

Low-bleed pneumatic devices mean automated flow control devices powered by

pressurized natural gas and used for maintaining a process condition such as liquid level, 

pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by the 

process condition flows to a valve actuator controller where it vents continuously (bleeds) to the 

atmosphere at a rate equal to or less than six standard cubic feet per hour.

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 
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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 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 applies to the midgrade categories of Conventional-Summer, 

Conventional-Winter, Reformulated-Summer, and Reformulated-Winter. For midgrade 

categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this 
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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 byproducts (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 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 
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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. Household waste includes material discarded by single and multiple 

residential dwellings, hotels, motels, and other similar permanent or temporary housing 

establishments or facilities. Commercial/retail waste includes material discarded by stores, 

offices, restaurants, warehouses, non-manufacturing activities at industrial facilities, and other 

similar establishments or facilities. Institutional waste includes material discarded by schools, 

nonmedical waste discarded by hospitals, material discarded by non-manufacturing activities at 

prisons and government facilities, and material discarded by other similar establishments or 

facilities. Household, commercial/retail, and institutional wastes include yard waste, refusederived fuel, and motor vehicle maintenance materials. Insofar as there is separate collection, 

processing and disposal of industrial source waste streams consisting of used oil, wood pallets, 

construction, renovation, and demolition wastes (which includes, but is not limited to, railroad 

ties and telephone poles), paper, clean wood, plastics, industrial process or manufacturing 

wastes, medical waste, motor vehicle parts or vehicle fluff, or used tires that do not contain 

hazardous waste identified or listed under 42 U.S.C. §6921, such wastes are not municipal solid 

waste. However, such wastes qualify as municipal solid waste where they are collected with 

other municipal solid waste or are otherwise combined with other municipal solid waste for 

processing and/or disposal.

Municipal wastewater treatment plant means a series of treatment processes used to 

remove contaminants and pollutants from domestic, business, and industrial wastewater collected 
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in city sewers and transported to a centralized wastewater treatment system such as a publicly 

owned treatment works (POTW).

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 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 the principal constituent 

is methane. Natural gas may be field quality or pipeline quality.

Natural gas driven pneumatic pump means a pump that uses pressurized natural gas to 

move a piston or diaphragm, which pumps liquids on the opposite side of the piston or 

diaphragm.

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. 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.

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.
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Non-crude feedstocks means any petroleum product or natural gas liquid that enters the 

refinery to be further refined or otherwise used on site.

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 byproducts are not recovered.

North American Industry Classification System (NAICS) code(s) means the six-digit 

code(s) that represents the product(s)/activity(s)/service(s) at a facility or supplier as listed in the 

FEDERAL REGISTER and defined in “North American Industrial Classification System Manual 

2007,” available from the U.S. Department of Commerce, National Technical Information 

Service, Alexandria, VA 22312, phone (703) 605-6000 or (800) 553-6847. 

http://www.census.gov/eos/www/naics/.

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 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.
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Other fluorinated GHGs means fluorinated GHGs that are none of the following: Fully 

fluorinated GHGs; saturated hydrofluorocarbons with 2 or fewer carbon-hydrogen bonds; 

saturated hydrofluorocarbons with 3 or more carbon-hydrogen bonds; saturated 

hydrofluoroethers and hydrochlorofluoroethers with 1 carbon-hydrogen bond; saturated 

hydrofluoroethers and hydrochlorofluoroethers with 2 carbon-hydrogen bonds; saturated 

hydrofluoroethers and hydrochlorofluoroethers with 3 or more carbon-hydrogen bonds; 

fluorinated formates; fluorinated acetates, carbonofluoridates, and fluorinated alcohols other than 

fluorotelomer alcohols; unsaturated PFCs, unsaturated HFCs, unsaturated HCFCs, unsaturated 

halogenated ethers, unsaturated halogenated esters, fluorinated aldehydes, and fluorinated 

ketones; fluorotelomer alcohols; or fluorinated GHGs with carbon-iodine bonds.

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.

Outer Continental Shelf means all submerged lands lying seaward and outside of the area 

of lands beneath navigable waters as defined in 43 U.S.C. 1331, and of which the subsoil and 

seabed appertain to the United States and are subject to its jurisdiction and control.

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.

Oxygenates means substances which, when added to gasoline, increase the oxygen 

content of the gasoline. Common oxygenates are ethanol, methyl tertiary butyl ether (MTBE), 
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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 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 
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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.

Physical address, with respect to a United States parent company as defined in this 

section, means the street address, city, state and zip code of that company's physical location.

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. This usually

occurs with little or no added water for periods less than one year.

Plant code means either of the following:

(1) The Plant ID code assigned by the Department of Energy's Energy Information 

Administration. The Energy Information Administration Plant ID code is also referred to as the 

“ORIS code”, “ORISPL code”, “Facility ID”, or “Facility code”, among other names.

(2) If a Plant ID code has not been assigned by the Department of Energy's Energy 

Information Administration, then plant code means a code beginning with “88” assigned by the 

EPA's Clean Air Markets Division for electronic reporting.

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.
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(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.

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

categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this 
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definition refers to the expected octane rating of the finished gasoline after oxygenate has been 

added to the RBOB or CBOB.

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 

spring-loaded 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.

Primary fuel means the fuel that provides the greatest percentage of the annual heat input 

to a stationary fuel combustion unit.

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 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: Is discharged through a conveyance to the 

atmosphere either directly or after passing through a control device; originates from a unit 
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operation, including but not limited to reactors (including reformers, crackers, and furnaces, and 

separation equipment for products and recovered byproducts); and 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.

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.
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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.

Reciprocating compressor means a piece of equipment that increases the pressure of a 

process natural gas or CO2 by positive displacement, employing linear movement of a shaft 

driving a piston in a cylinder.

Reciprocating compressor rod packing means a series of flexible rings in machined metal 

cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount 

of compressed natural gas or CO2 that escapes to the atmosphere.

Re-condenser means heat exchangers that cool compressed boil-off gas to a temperature 

that will condense natural gas to a liquid.

Reformulated-Summer 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, 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 
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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 Reformulated-Winter. 

For regular grade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOBWinter, this definition 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.

Reporting year means the calendar year during which the GHG data are required to be 

collected for purposes of the annual GHG report. For example, reporting year 2014 is January 1, 

2014 through December 31, 2014, and the annual report for reporting year 2014 is submitted to 

EPA on March 31, 2015.

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.
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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.

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 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.
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Sales oil means produced crude oil or condensate measured at the production lease 

automatic custody transfer (LACT) meter or custody transfer tank gauge.

Saturated hydrochlorofluoroethers (HCFEs) means fluorinated GHGs in which two 

hydrocarbon groups are linked by an oxygen atom; in which two or more, but not all, of the 

hydrogen atoms in the hydrocarbon groups have been replaced by fluorine atoms and chlorine 

atoms; and which contain only single bonds.

Saturated hydrofluorocarbons (HFCs) means fluorinated GHGs that are 

hydrofluorocarbons and that contain only single bonds.

Saturated hydrofluoroethers (HFEs) means fluorinated GHGs in which two hydrocarbon 

groups are linked by an oxygen atom; in which one or more, but not all, of the hydrogen atoms in 

the hydrocarbon groups have been replaced by fluorine atoms; and which contain only single 

bonds.

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 on-system receipt points from storage, peak shaving, and production.
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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.

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 by-products means plant matter such as vegetable waste, animal materials/wastes, 

and other solid biomass, except for wood, wood waste, and sulphite lyes (black liquor).

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.
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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.

Sour natural gas means natural gas that contains significant concentrations of hydrogen 

sulfide (H2S)and/or carbon dioxide (CO2) that exceed the concentrations specified for 

commercially saleable natural gas delivered from transmission and distribution pipelines.

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 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), for the purposes of this 

part, means either 60 or 68 degrees Fahrenheit and 14.7 pounds per square inch absolute.
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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.

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.

Supplemental fuel means a fuel burned within a petrochemical process that is not 

produced within the process itself.
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Supplier means a producer, importer, or exporter in any supply category included in 

Table A-5 to this subpart, as defined by the corresponding subpart of this part.

Sweet gas is natural gas with low concentrations of hydrogen sulfide (H2S) and/or carbon 

dioxide (CO2) that does not require (or has already had) acid gas treatment to meet pipeline 

corrosion-prevention specifications for transmission and distribution.

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 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).
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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, the Commonwealth of 

Puerto Rico, American Samoa, the Virgin Islands, Guam, and any other Commonwealth,

territory or possession of the United States, as well as the territorial sea as defined by

Presidential Proclamation No. 5928.

United States parent company(s) means the highest-level United States company(s) with 

an ownership interest in the facility or supplier as of December 31 of the year for which data are 

being reported.

Unsaturated halogenated ethers means fluorinated GHGs in which two hydrocarbon 

groups are linked by an oxygen atom; in which one or more of the hydrogen atoms in the 

hydrocarbon groups have been replaced by fluorine atoms; and which contain one or more bonds 

that are not single bonds. Unsaturated ethers include unsaturated HFEs.

Unsaturated hydrochlorofluorocarbons (HCFCs) means fluorinated GHGs that contain 

only carbon, chlorine, fluorine, and hydrogen and that contain one or more bonds that are not 

single bonds.

Unsaturated hydrofluorocarbons (HFCs) means fluorinated GHGs that are 

hydrofluorocarbons and that contain one or more bonds that are not single bonds.

Unsaturated perfluorocarbons (PFCs) means fluorinated GHGs that are perfluorocarbons 

and that contain one or more bonds that are not single bonds.
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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.

Used oil means a petroleum-derived or synthetically-derived oil whose physical 

properties have changed as a result of handling or use, such that the oil cannot be used for its 

original purpose. Used oil consists primarily of automotive oils (e.g., used motor oil, 

transmission oil, hydraulic fluids, brake fluid, etc.) and industrial oils (e.g., industrial engine oils, 

metalworking oils, process oils, industrial grease, etc).

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.

Vapor recovery system means any equipment located at the source of potential gas 

emissions to the atmosphere or to a flare, that is composed of piping, connections, and, if 

necessary, flow-inducing devices, and that is used for routing the gas back into the process as a 

product and/or fuel.

Vaporization unit means a process unit that performs controlled heat input to vaporize 

LNG to supply transmission and distribution pipelines or consumers with natural gas.

Vegetable oil means oils extracted from vegetation that are generally used as a feedstock 

in making biodiesel.
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Ventilation hole or shaft means a vent hole, shaft, mine portal, adit or other mine entrance 

or exits employed at an underground coal mine to serve as the outlet or conduit to move air from 

the ventilation system out of the mine.

Ventilation system means a system that is used to control the concentration of methane 

and other gases within mine working areas through mine ventilation, rather than a mine 

degasification system. A ventilation system consists of fans that move air through the mine 

workings to dilute methane concentrations.

Volatile solids are the organic material in livestock manure and consist of both 

biodegradable and non-biodegradable 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.

Well completions means the process that allows for the flow of petroleum or natural gas 

from newly drilled wells to expel drilling and reservoir fluids and test the reservoir flow 

characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank. 

Well completion also involves connecting the well bore to the reservoir, which may include 

treating the formation or installing tubing, packer(s), or lifting equipment, steps that do not 

significantly vent natural gas to the atmosphere. This process may also include high-rate 
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flowback of injected gas, water, oil, and proppant used to fracture and prop open new fractures in 

existing lower permeability gas reservoirs, steps that may vent large quantities of produced gas 

to the atmosphere.

Well workover means the process(es) of performing one or more of a variety of remedial 

operations on producing petroleum and natural gas wells to try to increase production. This 

process also includes high-rate flowback of injected gas, water, oil, and proppant used to refracture and prop-open new fractures in existing low permeability gas reservoirs, steps that may

vent large quantities of produced gas to the atmosphere.

Wellhead means the piping, casing, tubing and connected valves protruding above the 

earth's surface for an oil and/or natural gas well. The wellhead ends where the flow line connects 

to a wellhead valve. Wellhead equipment includes all equipment, permanent and portable, 

located on the improved land area (i.e. well pad) surrounding one or multiple wellheads.

Wet natural gas means natural gas in which water vapor exceeds the concentration 

specified for commercially saleable natural gas delivered from transmission and distribution 

pipelines. This input stream to a natural gas dehydrator is referred to as “wet gas.”

Wood residuals means materials recovered from three principal sources: Municipal solid 

waste (MSW); construction and demolition debris; and primary timber processing. Wood 

residuals recovered from MSW include wooden furniture, cabinets, pallets and containers, scrap 

lumber (from sources other than construction and demolition activities), and urban tree and 

landscape residues. Wood residuals from construction and demolition debris originate from the 

construction, repair, remodeling and demolition of houses and non-residential structures. Wood 

residuals from primary timber processing include bark, sawmill slabs and edgings, sawdust, and 

peeler log cores. Other sources of wood residuals include, but are not limited to, railroad ties, 
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telephone and utility poles, pier and dock timbers, wastewater process sludge from paper mills, 

trim, sander dust, and sawdust from wood products manufacturing (including resinated wood 

product residuals), and logging residues.

Wool fiberglass means fibrous glass of random texture, including fiberglass insulation, 

and other products listed in NAICS 327993.

Working capacity, for the purposes of subpart TT of this part, 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 percent filled and/or 

100 percent emptied for each load.

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 
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Avenue, NW., Washington, DC, phone (202) 566-1744 and at the National Archives and 

Records Administration (NARA). For information on the availability of this material at NARA, 

call 202-741-6030, or go to: 

http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.

(a)-(b) [Reserved]

(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 § 98.124(m)(1), § 98.324(e), § 

98.354(d), § 98.354(h), § 98.344(c) and § 98.364(e).

(2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine 

Meters, IBR approved for § 98.124(m)(2), § 98.324(e), § 98.344(c), § 98.354(h), and § 

98.364(e).

(3) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed 

Conduits Using Transit-Time Ultrasonic Flow Meters, IBR approved for § 98.124(m)(3) and § 

98.354(d).
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(4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex 

Flowmeters, IBR approved for § 98.124(m)(4), § 98.324(e), § 98.344(c), § 98.354(h), 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 § 98.124(m)(5), § 98.324(e), § 98.344(c), § 

98.354(h), and § 98.364(e).

(6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed 

Conduits by Weighing Method, IBR approved for § 98.124(m)(6).

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

Flowmeters, IBR approved for § 98.124(m)(7), § 98.324(e), § 98.344(c), and § 98.354(h).

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

Orifice Meters, IBR approved for § 98.124(m)(8), § 98.324(e), § 98.344(c), § 98.354(h), and § 

98.364(e).

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

Electromagnetic Flow Meters, IBR approved for § 98.354(d).

(10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable Area Meters, 

IBR approved for § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e).

(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).
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(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.

(4) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for § 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) [Reserved]

(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 § 

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

98.324(d), § 98.354(g), and § 98.344(b).

(11) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed 

Gas by Gas Chromatography, IBR approved for § 98.74(c), § 98.164(b), § 98.254(d), § 

98.324(d), § 98.344(b), § 98.354(g), and § 98.364(c).

(12) ASTM D2013-07 Standard Practice for Preparing Coal Samples for Analysis, IBR 

approved for § 98.164(b).
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(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 § 98.74(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 § 98.74(c) and § 98.254(d)(6).

(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).

(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 § 98.74(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 § 98.254(e).
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(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).

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

Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR approved for § 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 § 98.254(e) and § 

98.324(d).

(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 § 98.74(c), § 98.164(b), § 98.244(b), and § 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 § 98.74(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) [Reserved]

(29) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of Process 

Vents With a Portable Gas Chromatograph, IBR approved for § 98.244(b).
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(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), Table I-9 to subpart I of this part, § 98.224(b), and § 98.414(n).

(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 D6866-12 Standard Test Methods for Determining the Biobased Content of 

Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis, IBR approved for § 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 Stationary

Emissions Sources, IBR approved for § 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) [Reserved]
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(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), § 98.254(d), § 98.324(d), § 98.344(b), and § 98.354(g).

(43) ASTM D1941-91 (Reapproved 2007) Standard Test Method for Open Channel Flow 

Measurement of Water with the Parshall Flume, approved June 15, 2007, IBR approved for § 

98.354(d).

(44) ASTM D5614-94 (Reapproved 2008) Standard Test Method for Open Channel Flow 

Measurement of Water with Broad-Crested Weirs, approved October 1, 2008, IBR approved for 

§ 98.354(d).

(45) 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, IBR approved for § 98.144(b).

(46) ASTM D2879-97 (Reapproved 2007) Standard Test Method for Vapor PressureTemperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope 

(ASTM D2879), approved May 1, 2007, IBR approved for § 98.128.

(47) ASTM D7359-08 Standard Test Method for Total Fluorine, Chlorine and Sulfur in 

Aromatic Hydrocarbons and Their Mixtures by Oxidative Pyrohydrolytic Combustion followed 

by Ion Chromatography Detection (Combustion Ion Chromatography-CIC) (ASTM D7359), 

approved October 15, 2008, IBR approved for § 98.124(e)(2).
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(48) ASTM D2593-93 (Reapproved 2009) Standard Test Method for Butadiene Purity

and Hydrocarbon Impurities by Gas Chromatography, approved July 1, 2009, IBR approved for 

§ 98.244(b)(4)(xi).

(49) ASTM D7633-10 Standard Test Method for Carbon Black—Carbon Content, 

approved May 15, 2010, IBR approved for § 98.244(b)(4)(xii).

(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) [Reserved]

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

Chromatography, IBR approved for § 98.164(b), § 98.254(d), § 98.344(b), and § 98.354(g).

(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).

(2) ISO 3171: Petroleum Liquids—Automatic pipeline sampling—Second Edition 1988-

12-01, IBR approved for § 98.164(b).

(3) [Reserved]

(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).
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(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—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).
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(2) T684 om-06 Gross Heating Value of Black Liquor, TAPPI, incorporation by

reference (IBR) approved for § 98.274(b).

(k) The following material is available for purchase from Standard Methods, at 

http://www.standardmethods.org, (877) 574-1233; or, through a joint publication agreement 

from the American Public Health Association (APHA), P.O. Box 933019, Atlanta, GA 31193-

3019, (888) 320-APHA (2742), http://www.apha.org/publications/pubscontact/.

(1) Method 2540G Total, Fixed, and Volatile Solids in Solid and Semisolid Samples, IBR 

approved for § 98.464(b).

(2) [Reserved]

(l) The following material is available from the U.S. Department of Labor, Mine Safety 

and Health Administration, 1100 Wilson Boulevard, 21st Floor, Arlington, VA 22209-3939, 

(202) 693-9400, http://www.msha.gov.

(1) Coal Mine Safety and Health General Inspection Procedures Handbook, Handbook 

Number: PH13-V-1, February 2013, IBR approved for § 98.324(b).

(2) [Reserved]

(m) The following material is available from the U.S. Environmental Protection Agency, 

1200 Pennsylvania Avenue, NW., Washington, DC 20460, (202) 272-0167, http://www.epa.gov.

(1) NPDES Compliance Inspection Manual, Chapter 5, Sampling, EPA 305-X-04-001, 

July 2004, http://www.epa.gov/compliance/monitoring/programs/cwa/npdes.html, IBR approved 

for § 98.354(c).

(2) U.S. EPA NPDES Permit Writers' Manual, Section 7.1.3, Sample Collection 

Methods, EPA 833-B-96-003, December 1996, http://www.epa.gov/npdes/pubs/owm0243.pdf, 

IBR approved for § 98.354(c).
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(3) Protocol for Measuring Destruction or Removal Efficiency (DRE) of Fluorinated 

Greenhouse Gas Abatement Equipment in Electronics Manufacturing, Version 1, EPA-430-R10-003, March 2010 (EPA 430-R-10-003), http://www.epa.gov/semiconductorpfc/documents/dre_protocol.pdf, IBR approved for § 98.94(f)(4)(i), § 98.94(g)(3), § 98.97(d)(4), 

§ 98.98, Appendix A to subpart I of this part, § 98.124(e)(2), and § 98.414(n)(1).

(4) Emissions Inventory Improvement Program, Volume II: Chapter 16, Methods for 

Estimating Air Emissions from Chemical Manufacturing Facilities, August 2007, Final, 

http://www.epa.gov/ttnchie1/eiip/techreport/volume02/index.html, IBR approved for § 

98.123(c)(1)(i)(A).

(5) Protocol for Equipment Leak Emission Estimates, EPA-453/R-95-017, November 

1995 (EPA-453/R-95-017), http://www.epa.gov/ttnchie1/efdocs/equiplks.pdf, IBR approved for 

§ 98.123(d)(1)(i), § 98.123(d)(1)(ii), § 98.123(d)(1)(iii), and § 98.124(f)(2).

(6) Tracer Gas Protocol for the Determination of Volumetric Flow Rate Through the 

Ring Pipe of the Xact Multi-Metals Monitoring System, also known as Other Test Method 24 

(Tracer Gas Protocol), Eli Lilly and Company Tippecanoe Laboratories, September 2006, 

http://www.epa.gov/ttn/emc/prelim/otm24.pdf, IBR approved for § 98.124(e)(1)(ii).

(7) Approved Alternative Method 012: An Alternate Procedure for Stack Gas Volumetric 

Flow Rate Determination (Tracer Gas) (ALT-012), U.S. Environmental Protection Agency

Emission Measurement Center, May 23, 1994, http://www.epa.gov/ttn/emc/approalt/alt-012.pdf, 

IBR approved for § 98.124(e)(1)(ii).

(8) Protocol for Measurement of Tetrafluoromethane (CF4) and Hexafluoroethane (C2F6) 

Emissions from Primary Aluminum Production (2008), http://www.epa.gov/highgwp/aluminumpfc/documents/measureprotocol.pdf, IBR approved for § 98.64(a).
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(9) AP 42, Section 5.2, Transportation and Marketing of Petroleum Liquids, July 2008, 

(AP 42, Section 5.2); http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf; in Chapter 5, 

Petroleum Industry, of AP 42, Compilation of Air Pollutant Emission Factors, 5th Edition, 

Volume I, IBR approved for § 98.253(n).

(10) Method 9060A, Total Organic Carbon, Revision 1, November 2004 (Method 

9060A), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9060a.pdf; in EPA Publication 

No. SW-846, “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” Third 

Edition, IBR approved for § 98.244(b)(4)(viii).

(11) Method 8031, Acrylonitrile By Gas Chromatography, Revision 0, September 1994 

(Method 8031), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8031.pdf; in EPA 

Publication No. SW-846, “Test Methods for Evaluating Solid Waste, Physical/Chemical 

Methods,” Third Edition, IBR approved for § 98.244(b)(4)(viii).

(12) Method 8021B, Aromatic and Halogenated Volatiles By Gas Chromatography Using 

Photoionization and/or Electrolytic Conductivity Detectors, Revision 2, December 1996 (Method 

8021B). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8021b.pdf; in EPA Publication 

No. SW-846, “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” Third

Edition, IBR approved for § 98.244(b)(4)(viii).

(13) Method 8015C, Nonhalogenated Organics By Gas Chromatography, Revision 3, 

February 2007 (Method 8015C). 

http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8015c.pdf; in EPA Publication No. 

SW-846, “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” Third 

Edition, IBR approved for § 98.244(b)(4)(viii).
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Page 111 of 129

(14) AP 42, Section 7.1, Organic Liquid Storage Tanks, November 2006 (AP 42, Section 

7.1), http://www.epa.gov/ttn/chief/ap42/ch07/final/c07s01.pdf; in Chapter 7, Liquid Storage 

Tanks, of AP 42, Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I, IBR 

approved for § 98.253(m)(1) and § 98.256(o)(2)(i).

(n)-(o) [Reserved]

(p) The following material is available for purchase from the American Association of 

Petroleum Geologists, 1444 South Boulder Avenue, Tulsa, Oklahoma 74119, (918) 584-2555, 

http://www.aapg.org.

(1) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, 

Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 

10 (October 1991), pages 1644-1651, IBR approved for § 98.238.

(2) Alaska Geological Province Boundary Map, Compiled by the American Association 

of Petroleum Geologists Committee on Statistics of Drilling in cooperation with the USGS, 

1978, IBR approved for § 98.238.

(q) The following material is available from the Energy Information Administration 

(EIA), 1000 Independence Ave., SW., Washington, DC 20585, (202) 586-8800, 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/field_code_master_list/curren

t/pdf/fcml_all.pdf.

(1) Oil and Gas Field Code Master List 2008, DOE/EIA0370(08), January 2009, IBR 

approved for § 98.238.

(2) [Reserved]

§ 98.8 What are the compliance and enforcement provisions of this part?
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Page 112 of 129

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 

must be submitted electronically and in a format as specified by the Administrator. For example, 

any requests, notifications and communications that can be submitted through the electronic 

GHG reporting tool, must be submitted through that tool. If not specified, requests, notifications 

or communications 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.
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Page 113 of 129

Table A-1 to Subpart A of Part 98—Global Warming Potentials

[100-Year Time Horizon]

Name CAS No. Chemical formula

Global

warming

potential

(100 yr.)

Chemical-Specific GWPs

Carbon dioxide 124-38-9 CO2 1

Methane 74-82-8 CH4

a

25

Nitrous oxide 10024-97-2 N2O

a

298

Fully Fluorinated GHGs

Sulfur hexafluoride 2551-62-4 SF6

a

22,800

Trifluoromethyl sulphur pentafluoride 373-80-8 SF5CF3 17,700

Nitrogen trifluoride 7783-54-2 NF3 17,200

PFC-14 (Perfluoromethane) 75-73-0 CF4

a

7,390

PFC-116 (Perfluoroethane) 76-16-4 C2F6

a

12,200

PFC-218 (Perfluoropropane) 76-19-7 C3F8

a

8,830

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

PFC-3-1-10 (Perfluorobutane) 355-25-9 C4F10

a

8,860

PFC-318 (Perfluorocyclobutane) 115-25-3 C-C4F8

a

10,300

PFC-4-1-12 (Perfluoropentane) 678-26-2 C5F12

a

9,160

PFC-5-1-14 (Perfluorohexane, FC-72) 355-42-0 C6F14

a

9,300

PFC-6-1-12 335-57-9 C7F16; CF3(CF2)5CF3

b

7,820

PFC-7-1-18 307-34-6 C8F18; CF3(CF2)6CF3

b

7,620

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

PFPMIE (HT-70) NA CF3OCF(CF3)CF2OCF2OCF3 10,300

Perfluorodecalin (cis) 60433-11-6 Z-C10F18

b

7,236

Perfluorodecalin (trans) 60433-12-7 E-C10F18

b

6,288

Saturated Hydrofluorocarbons (HFCs) With Two or Fewer Carbon-Hydrogen Bonds

HFC-23 75-46-7 CHF3

a

14,800

HFC-32 75-10-5 CH2F2

a

675

HFC-125 354-33-6 C2HF5

a

3,500

HFC-134 359-35-3 C2H2F4

a

1,100

HFC-134a 811-97-2 CH2FCF3

a

1,430

HFC-227ca 2252-84-8 CF3CF2CHF2

b

2640
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HFC-227ea 431-89-0 C3HF7

a

3,220

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

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

HFC-236fa 690-39-1 C3H2F6

a

9,810

HFC-329p 375-17-7 CHF2CF2CF2CF3

b

2360

HFC-43-10mee 138495-42-8 CF3CFHCFHCF2CF3

a

1,640

Saturated Hydrofluorocarbons (HFCs) With Three or More Carbon-Hydrogen Bonds

HFC-41 593-53-3 CH3F

a

92

HFC-143 430-66-0 C2H3F3

a

353

HFC-143a 420-46-2 C2H3F3

a

4,470

HFC-152 624-72-6 CH2FCH2F 53

HFC-152a 75-37-6 CH3CHF2

a

124

HFC-161 353-36-6 CH3CH2F 12

HFC-245ca 679-86-7 C3H3F5

a

693

HFC-245cb 1814-88-6 CF3CF2CH3

b

4620

HFC-245ea 24270-66-4 CHF2CHFCHF2

b

235

HFC-245eb 431-31-2 CH2FCHFCF3

b

290

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

HFC-263fb 421-07-8 CH3CH2CF3

b

76

HFC-272ca 420-45-1 CH3CF2CH3

b

144

HFC-365mfc 406-58-6 CH3CF2CH2CF3 794

Saturated Hydrofluoroethers (HFEs) and Hydrochlorofluoroethers (HCFEs) With One Carbon-Hydrogen 

Bond

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

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

HFE-329mcc2 134769-21-4 CF3CF2OCF2CHF2 919

HFE-329me3 428454-68-6 CF3CFHCF2OCF3

b

4,550

1,1,1,2,2,3,3-Heptafluoro-3-(1,2,2,2-tetrafluoroethoxy)-

propane

3330-15-2 CF3CF2CF2OCHFCF3

b

6,490

Saturated HFEs and HCFEs With Two Carbon-Hydrogen Bonds

HFE-134 (HG-00) 1691-17-4 CHF2OCHF2 6,320

HFE-236ca 32778-11-3 CHF2OCF2CHF2

b

4,240

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

HFE-236ea2 (Desflurane) 57041-67-5 CHF2OCHFCF3 989
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HFE-236fa 20193-67-3 CF3CH2OCF3 487

HFE-338mcf2 156053-88-2 CF3CF2OCH2CF3 552

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

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

HFE-43-10pccc (H-Galden 1040x, HG-11) E1730133 CHF2OCF2OC2F4OCHF2 1,870

HCFE-235ca2 (Enflurane) 13838-16-9 CHF2OCF2CHFCl b583

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

HG-02 205367-61-9 HF2C-(OCF2CF2)2-OCF2H

b

3,825

HG-03 173350-37-3 HF2C-(OCF2CF2)3-OCF2H

b

3,670

HG-20 249932-25-0 HF2C-(OCF2)2-OCF2H

b

5,300

HG-21 249932-26-1 HF2C-OCF2CF2OCF2OCF2OCF2H

b

3,890

HG-30 188690-77-9 HF2C-(OCF2)3-OCF2H

b

7,330

1,1,3,3,4,4,6,6,7,7,9,9,10,10,12,12,13,13,15,15-

eicosafluoro-2,5,8,11,14-Pentaoxapentadecane

173350-38-4 HCF2O(CF2CF2O)4CF2H

b

3,630

1,1,2-Trifluoro-2-(trifluoromethoxy)-ethane 84011-06-3 CHF2CHFOCF3

b

1,240

Trifluoro(fluoromethoxy)methane 2261-01-0 CH2FOCF3

b

751

Saturated HFEs and HCFEs With Three or More Carbon-Hydrogen Bonds

HFE-143a 421-14-7 CH3OCF3 756

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-263m1; R-E-143a 690-22-2 CF3OCH2CH3

b

29

HFE-347mcc3 (HFE-7000) 375-03-1 CH3OCF2CF2CF3 575

HFE-347mcf2 171182-95-9 CF3CF2OCH2CHF2 374

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

HFE-347mmz1 (Sevoflurane) 28523-86-6 (CF3)2CHOCH2F

c

216

HFE-347pcf2 406-78-0 CHF2CF2OCH2CF3 580

HFE-356mec3 382-34-3 CH3OCF2CHFCF3 101

HFE-356mff2 333-36-8 CF3CH2OCH2CF3

b

17

HFE-356mmz1 13171-18-1 (CF3)2CHOCH3 27

HFE-356pcc3 160620-20-2 CH3OCF2CF2CHF2 110
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HFE-356pcf2 50807-77-7 CHF2CH2OCF2CHF2 265

HFE-356pcf3 35042-99-0 CHF2OCH2CF2CHF2 502

HFE-365mcf2 22052-81-9 CF3CF2OCH2CH3

b

58

HFE-365mcf3 378-16-5 CF3CF2CH2OCH3 11

HFE-374pc2 512-51-6 CH3CH2OCF2CHF2 557

HFE-449s1 (HFE-7100) Chemical blend 163702-07-6 C4F9OCH3 297

 163702-08-7 (CF3)2CFCF2OCH3

HFE-569sf2 (HFE-7200) Chemical blend 163702-05-4 C4F9OC2H5 59

 163702-06-5 (CF3)2CFCF2OC2H5

HG'-01 73287-23-7 CH3OCF2CF2OCH3

b

222

HG'-02 485399-46-0 CH3O(CF2CF2O)2CH3

b

236

HG'-03 485399-48-2 CH3O(CF2CF2O)3CH3

b

221

Difluoro(methoxy)methane 359-15-9 CH3OCHF2

b

144

2-Chloro-1,1,2-trifluoro-1-methoxyethane 425-87-6 CH3OCF2CHFCl b122

1-Ethoxy-1,1,2,2,3,3,3-heptafluoropropane 22052-86-4 CF3CF2CF2OCH2CH3

b

61

2-Ethoxy-3,3,4,4,5-pentafluorotetrahydro-2,5-bis[1,2,2,2-

tetrafluoro-1-(trifluoromethyl)ethyl]-furan

920979-28-8 C12H5F19O2

b

56

1-Ethoxy-1,1,2,3,3,3-hexafluoropropane 380-34-7 CF3CHFCF2OCH2CH3

b

23

Fluoro(methoxy)methane 460-22-0 CH3OCH2F

b

13

1,1,2,2-Tetrafluoro-3-methoxy-propane; Methyl 2,2,3,3-

tetrafluoropropyl ether

60598-17-6 CHF2CF2CH2OCH3

b

0.5

1,1,2,2-Tetrafluoro-1-(fluoromethoxy)ethane 37031-31-5 CH2FOCF2CF2H

b

871

Difluoro(fluoromethoxy)methane 461-63-2 CH2FOCHF2

b

617

Fluoro(fluoromethoxy)methane 462-51-1 CH2FOCH2F

b

130

Fluorinated Formates

Trifluoromethyl formate 85358-65-2 HCOOCF3

b

588

Perfluoroethyl formate 313064-40-3 HCOOCF2CF3

b

580

1,2,2,2-Tetrafluoroethyl formate 481631-19-0 HCOOCHFCF3

b

470

Perfluorobutyl formate 197218-56-7 HCOOCF2CF2CF2CF3

b

392

Perfluoropropyl formate 271257-42-2 HCOOCF2CF2CF3

b

376

1,1,1,3,3,3-Hexafluoropropan-2-yl formate 856766-70-6 HCOOCH(CF3)2

b

333

2,2,2-Trifluoroethyl formate 32042-38-9 HCOOCH2CF3

b

33

3,3,3-Trifluoropropyl formate 1344118-09-7 HCOOCH2CH2CF3

b

17
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Fluorinated Acetates

Methyl 2,2,2-trifluoroacetate 431-47-0 CF3COOCH3

b

52

1,1-Difluoroethyl 2,2,2-trifluoroacetate 1344118-13-3 CF3COOCF2CH3

b

31

Difluoromethyl 2,2,2-trifluoroacetate 2024-86-4 CF3COOCHF2

b

27

2,2,2-Trifluoroethyl 2,2,2-trifluoroacetate 407-38-5 CF3COOCH2CF3

b

7

Methyl 2,2-difluoroacetate 433-53-4 HCF2COOCH3

b

3

Perfluoroethyl acetate 343269-97-6 CH3COOCF2CF3

b

2.1

Trifluoromethyl acetate 74123-20-9 CH3COOCF3

b

2.0

Perfluoropropyl acetate 1344118-10-0 CH3COOCF2CF2CF3

b

1.8

Perfluorobutyl acetate 209597-28-4 CH3COOCF2CF2CF2CF3

b

1.6

Ethyl 2,2,2-trifluoroacetate 383-63-1 CF3COOCH2CH3

b

1.3

Carbonofluoridates

Methyl carbonofluoridate 1538-06-3 FCOOCH3

b

95

1,1-Difluoroethyl carbonofluoridate 1344118-11-1 FCOOCF2CH3

b

27

Fluorinated Alcohols Other Than Fluorotelomer Alcohols

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

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

2,2,3,3,3-Pentafluoropropanol 422-05-9 CF3CF2CH2OH 42

2,2,3,3,4,4,4-Heptafluorobutan-1-ol 375-01-9 C3F7CH2OH b25

2,2,2-Trifluoroethanol 75-89-8 CF3CH2OH b20

2,2,3,4,4,4-Hexafluoro-1-butanol 382-31-0 CF3CHFCF2CH2OH b17

2,2,3,3-Tetrafluoro-1-propanol 76-37-9 CHF2CF2CH2OH b13

2,2-Difluoroethanol 359-13-7 CHF2CH2OH b3

2-Fluoroethanol 371-62-0 CH2FCH2OH b1.1

4,4,4-Trifluorobutan-1-ol 461-18-7 CF3(CH2)2CH2OH b0.05

Unsaturated Perfluorocarbons (PFCs)

PFC-1114; TFE 116-14-3 CF2=CF2; C2F4

b

0.004

PFC-1216; Dyneon HFP 116-15-4 C3F6; CF3CF=CF2

b

0.05

PFC C-1418 559-40-0 c-C5F8

b

1.97

Perfluorobut-2-ene 360-89-4 CF3CF=CFCF3

b

1.82

Perfluorobut-1-ene 357-26-6 CF3CF2CF=CF2

b

0.10

Perfluorobuta-1,3-diene 685-63-2 CF2=CFCF=CF2

b

0.003

Unsaturated Hydrofluorocarbons (HFCs) and Hydrochlorofluorocarbons (HCFCs)

HFC-1132a; VF2 75-38-7 C2H2F2 , CF2=CH2

b

0.04
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HFC-1141; VF 75-02-5 C2H3F, CH2=CHF b0.02

(E)-HFC-1225ye 5595-10-8 CF3CF=CHF(E) b0.06

(Z)-HFC-1225ye 5528-43-8 CF3CF=CHF(Z) b0.22

Solstice 1233zd(E) 102687-65-0 C3H2ClF3; CHCl=CHCF3

b

1.34

HFC-1234yf; HFO-1234yf 754-12-1 C3H2F4; CF3CF=CH2

b

0.31

HFC-1234ze(E) 1645-83-6 C3H2F4; trans-CF3CH=CHF b0.97

HFC-1234ze(Z) 29118-25-0 C3H2F4cis-CF3CH=CHF; 

CF3CH=CHF

b

0.29

HFC-1243zf; TFP 677-21-4 C3H3F3, CF3CH=CH2

b

0.12

(Z)-HFC-1336 692-49-9 CF3CH=CHCF3(Z)

b

1.58

HFC-1345zfc 374-27-6 C2F5CH=CH2

b

0.09

Capstone 42-U 19430-93-4 C6H3F9, CF3(CF2)3CH=CH2

b

0.16

Capstone 62-U 25291-17-2 C8H3F13, CF3(CF2)5CH=CH2

b

0.11

Capstone 82-U 21652-58-4 C10H3F17, CF3(CF2)7CH=CH2

b

0.09

Unsaturated Halogenated Ethers

PMVE; HFE-216 1187-93-5 CF3OCF=CF2

b

0.17

Fluoroxene 406-90-6 CF3CH2OCH=CH2

b

0.05

Fluorinated Aldehydes

3,3,3-Trifluoro-propanal 460-40-2 CF3CH2CHO b0.01

Fluorinated Ketones

Novec 1230 (perfluoro (2-methyl-3-pentanone)) 756-13-8 CF3CF2C(O)CF (CF3)2

b

0.1

Fluorotelomer Alcohols

3,3,4,4,5,5,6,6,7,7,7-Undecafluoroheptan-1-ol 185689-57-0 CF3(CF2)4CH2CH2OH b0.43

3,3,3-Trifluoropropan-1-ol 2240-88-2 CF3CH2CH2OH b0.35

3,3,4,4,5,5,6,6,7,7,8,8,9,9,9-Pentadecafluorononan-1-ol 755-02-2 CF3(CF2)6CH2CH2OH b0.33

3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,11,11,11-

Nonadecafluoroundecan-1-ol

87017-97-8 CF3(CF2)8CH2CH2OH b0.19

Fluorinated GHGs With Carbon-Iodine Bond(s)

Trifluoroiodomethane 2314-97-8 CF3I

b

0.4

Other Fluorinated Compounds

Dibromodifluoromethane (Halon 1202) 75-61-6 CBR2F2

b

231

2-Bromo-2-chloro-1,1,1-trifluoroethane (Halon2311/Halothane)151-67-7 CHBrClCF3

b

41
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Fluorinated GHG Groupd

Global

warming

potential

(100 yr.)

Default GWPs for Compounds for Which Chemical-Specific GWPs Are Not Listed Above

Fully fluorinated GHGs 10,000

Saturated hydrofluorocarbons (HFCs) with 2 or fewer carbon-hydrogen bonds 3,700

Saturated HFCs with 3 or more carbon-hydrogen bonds 930

Saturated hydrofluoroethers (HFEs) and hydrochlorofluoroethers (HCFEs) with 1 carbon-hydrogen 

bond

5,700

Saturated HFEs and HCFEs with 2 carbon-hydrogen bonds 2,600

Saturated HFEs and HCFEs with 3 or more carbon-hydrogen bonds 270

Fluorinated formates 350

Fluorinated acetates, carbonofluoridates, and fluorinated alcohols other than fluorotelomer alcohols 30

Unsaturated perfluorocarbons (PFCs), unsaturated HFCs, unsaturated hydrochlorofluorocarbons 

(HCFCs), unsaturated halogenated ethers, unsaturated halogenated esters, fluorinated aldehydes, and 

fluorinated ketones

1

Fluorotelomer alcohols 1

Fluorinated GHGs with carbon-iodine bond(s) 1

Other fluorinated GHGs 2,000

a The GWP for this compound was updated in the final rule published on November 29, 2013 [78 FR 71904] and 

effective on January 1, 2014.

b

his compound was added to Table A-1 in the final rule published on December 11, 2014, and effective on 

January 1, 2015.

c The GWP for this compound was updated in the final rule published on December 11, 2014, and effective on 

January 1, 2015 .

d

For electronics manufacturing (as defined in §98.90), the term “fluorinated GHGs” in the definition of each 

fluorinated GHG group in §98.6 shall include fluorinated heat transfer fluids (as defined in §98.98), whether or 

not they are also fluorinated GHGs.

Table A-2 to Subpart A of Part 98—Units of Measure Conversions

To convert from To Multiply by

Kilograms (kg) Pounds (lbs) 2.20462

Pounds (lbs) Kilograms (kg) 0.45359

Pounds (lbs) Metric tons 4.53592 × 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
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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 × 10−5

Square meters (m2) Acres 2.47105 × 10−4

Square miles (mi2) Square kilometers (km2) 2.58999

Degrees Celsius (°C) Degrees Fahrenheit (°F) °C = (5/9) × (°F −32)

Degrees Fahrenheit (°F) Degrees Celsius (°C) °F = (9/5) × °C + 32

Degrees Celsius (°C) Kelvin (K) K = °C + 273.15

Kelvin (K) Degrees Rankine (°R) 1.8

Joules Btu 9.47817 × 10−4

Btu MMBtu 1 × 10−6

Pascals (Pa) Inches of Mercury (in Hg) 2.95334 × 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

Table A-3 to Subpart A of Part 98—Source Category List for §98.2(a)(1)

Source Categoriesa Applicable in Reporting Year 2010 and Future Years

Electricity generation units that report CO2 mass emissions year round through 40 CFR part 75 (subpart 

D).

Adipic acid production (subpart E).

Aluminum production (subpart F).

Ammonia manufacturing (subpart G).
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Cement production (subpart H).

HCFC-22 production (subpart O).

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 (subpart O).

Lime manufacturing (subpart S).

Nitric acid production (subpart V).

Petrochemical production (subpart X).

Petroleum refineries (subpart Y).

Phosphoric acid production (subpart Z).

Silicon carbide production (subpart BB).

Soda ash production (subpart CC).

Titanium dioxide production (subpart EE).

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.

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.

Additional Source Categoriesa Applicable in Reporting Year 2011 and Future Years

Electrical transmission and distribution equipment use at facilities where the total nameplate capacity of 

SF6 and PFC containing equipment exceeds 17,820 pounds, as determined under §98.301 (subpart DD).

Underground coal mines liberating 36,500,000 actual cubic feet of CH4 or more per year (subpart FF).

Geologic sequestration of carbon dioxide (subpart RR).

Electrical transmission and distribution equipment manufacture or refurbishment (subpart SS).

Injection of carbon dioxide (subpart UU).

a

Source categories are defined in each applicable subpart.

Table A-4 to Subpart A—Source Category List for §98.2(a)(2)

Source Categoriesa Applicable in Reporting Year 2010 and Future Years

Ferroalloy production (subpart K).

Glass production (subpart N).

Hydrogen production (subpart P).

Iron and steel production (subpart Q).

Lead production (subpart R).

Pulp and paper manufacturing (subpart AA).

Zinc production (subpart GG).

Additional Source Categoriesa Applicable in Reporting Year 2011 and Future Years
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Electronics manufacturing (subpart I)

Fluorinated gas production (subpart L)

Magnesium production (subpart T).

Petroleum and Natural Gas Systems (subpart W)

Industrial wastewater treatment (subpart II).

Industrial waste landfills (subpart TT).

a

Source categories are defined in each applicable subpart.

Table A-5 to Subpart A—Supplier Category List for §98.2(a)(4)

Supplier Categoriesa Applicable in Reporting Year 2010 and Future Years

Coal-to-liquids suppliers (subpart LL):

(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 that is equivalent to 25,000 

metric tons CO2e or more.

Petroleum product suppliers (subpart MM):

(A) All petroleum refineries that distill crude oil.

(B) Importers of an annual quantity of petroleum products and natural gas liquids that is 

equivalent to 25,000 metric tons CO2e or more.

(C) Exporters of an annual quantity of petroleum products and natural gas liquids that is 

equivalent to 25,000 metric tons CO2e or more.

Natural gas and natural gas liquids suppliers (subpart NN):

(A) All fractionators.

(B) Local natural gas distribution companies that deliver 460,000 thousand standard cubic 

feet or more of natural gas per year.

Industrial greenhouse gas suppliers (subpart OO):

(A) All producers of industrial greenhouse gases and fluorinated heat transfer fluids.

(B) Importers of industrial greenhouse gases and fluorinated heat transfer fluids with annual 

bulk imports of N2O, fluorinated GHG, fluorinated heat transfer fluids, and CO2 that in 

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, fluorinated heat transfer fluids, and CO2 that in combination are equivalent to 25,000 

metric tons CO2e or more.

(D) Facilities that destroy 25,000 mtCO2e or more of fluorinated GHGs or fluorinated heat 

transfer fluids annually.

Carbon dioxide suppliers (subpart PP):

(A) All producers of CO2.
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(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.

Additional Supplier Categories Applicableain Reporting Year 2011 and Future Years

Importers and exporters of fluorinated greenhouse gases contained in pre-charged equipment or closedcell foams (subpart QQ):

(A) Importers of an annual quantity of fluorinated greenhouse gases contained in precharged equipment or closed-cell foams that is equivalent to 25,000 metric tons CO2e or 

more.

(B) Exporters of an annual quantity of fluorinated greenhouse gases contained in pre-charged 

equipment or closed-cell foams that is equivalent to 25,000 metric tons CO2e or more.

a

Suppliers are defined in each applicable subpart.

Table A-6 to Subpart A of Part 98—Data Elements That Are Inputs to Emission Equations 

and for Which the Reporting Deadline Is March 31, 2013 

Subpart 

Rule citation

(40 CFR part 98) 

Specific data elements for which reporting date is March 31, 2013 (“All” 

means all data elements in the cited paragraph are not required to be 

reported until March 31, 2013) 

C 98.36(d)(1)(iv) All.

C 98.36(d)(2)(ii)(G) All.

C 98.36(d)(2)(iii)(G) All.

C 98.36(e)(2)(iv)(G) All.

C 98.36(e)(2)(viii)(A) All.

C 98.36(e)(2)(viii)(B) All.

C 98.36(e)(2)(viii)(C) All.

C 98.36(e)(2)(x)(A) All.

C 98.36(e)(2)(xi) All.

DD 98.306(a)(2) All.

DD 98.306(a)(3) All.

DD 98.306(d) All.

DD 98.306(e) All.

DD 98.306(f) All.

DD 98.306(g) All.

DD 98.306(h) All.

DD 98.306(i) All.

DD 98.306(j) All.
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DD 98.306(k) All.

DD 98.306(l) All.

FF 98.326(a) All.

FF 98.326(b) All.

FF 98.326(c) All.

FF 98.326(f) Only quarterly volumetric flow rate.

FF 98.326(g) Only quarterly CH4 concentration.

FF 98.326(h) Only weekly volumetric flow used to calculate CH4 liberated from 

degasification systems.

FF 98.326(j) All.

FF 98.326(k) All.

FF 98.326(o) All.

FF 98.326(p) Only assumed destruction efficiency for the primary destruction device and 

assumed destruction efficiency for the backup destruction device.

HH 98.346(a) Only year in which landfill first accepted waste, last year the landfill accepted 

waste (if used as an input in Equation HH-3), capacity of the landfill (if used as 

an input in Equation HH-3), and waste disposal quantity for each year of 

landfilling.

HH 98.346(b) Only quantity of waste determined using the methods in §98.343(a)(3)(i), 

quantity of waste determined using the methods in §98.343(a)(3)(ii), population 

served by the landfill for each year, and the value of landfill capacity (LFC) 

used in the calculation.

HH 98.346(c) All.

HH 98.346(d)(1) Only degradable organic carbon (DOC) value, and fraction of DOC dissimilated 

(DOCF) values.

HH 98.346(d)(2) All.

HH 98.346(e) Only fraction of CH4 in landfill gas and methane correction factor (MCF) 

values.

HH 98.346(f) Only surface area associated with each cover type.

HH 98.346(g) All.

HH 98.346(i)(5) Only annual operating hours for the destruction devices located at the landfill 

facility, and the destruction efficiency for the destruction devices associated 

with that measurement location.

HH 98.346(i)(6) All.

HH 98.346(i)(7) Only surface area specified in Table HH-3, estimated gas collection system 

efficiency, and annual operating hours of the gas collection system for each 

measurement locations.

HH 98.346(i)(9) Only CH4 generation value.

II 98.356(b)(1) All.
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II 98.356(b)(2) All.

II 98.356(b)(3) All.

II 98.356(b)(4) All.

II 98.356(b)(5) All.

II 98.356(d)(1) All.

II 98.356(d)(7) All.

II 98.356(d)(8) Only annual operating hours for the primary destruction device, annual 

operating hours for the backup destruction device, destruction efficiency of the 

primary destruction device, and destruction efficiency of the backup destruction 

device.

SS 98.456(a) All.

SS 98.456(b) All.

SS 98.456(c) All.

SS 98.456(d) All.

SS 98.456(e) All.

SS 98.456(f) All.

SS 98.456(g) All.

SS 98.456(h) All.

SS 98.456(i) All.

SS 98.456(j) All.

SS 98.456(m) All.

SS 98.456(n) All.

SS 98.456(o) All.

SS 98.456(q) All.

SS 98.456(r) All.

SS 98.456(s) All.

SS 98.456(t) Only for any missing data the substitute parameters used to estimate emissions 

in their absence.

TT 98.466(a)(2) All.

TT 98.466(a)(3) Only last year the landfill accepted waste (for closed landfills using Equation 

TT-4).

TT 98.466(a)(4) Only capacity of the landfill in metric tons (for closed landfills using Equation 

TT-4).

TT 98.466(b)(3) Only fraction of CH4 in landfill gas.

TT 98.466(b)(4) Only the methane correction factor (MCF) value used in the calculations.

TT 98.466(c)(4)(i) All.
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TT 98.466(c)(4)(ii) All.

TT 98.466(c)(4)(iii) All.

TT 98.466(d)(2) All.

TT 98.466(d)(3) Only degradable organic carbon (DOCx) value for each waste stream used in 

calculations.

TT 98.466(e)(2) Only surface area (in square meters) at the start of the reporting year for the 

landfill sections that contain waste and that are associated with the selected 

cover type (for facilities using a landfill gas collection system).

TT 98.466(f) All.

Table A-7 to Subpart A of Part 98—Data Elements That Are Inputs to Emission Equations 

and for Which the Reporting Deadline Is March 31, 2015

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is March 31, 2015

(“All” means all data elements in the cited paragraph are

not required to be reported until March 31, 2015)

A 98.3(d)(3)(v) All.a

C 98.36(b)(9)(iii) Only estimate of the heat input.a

C 98.36(c)(2)(ix) Only estimate of the heat input from each type of fuel listed in Table C-2.a

C 98.36(e)(2)(i) All.a

C 98.36(e)(2)(ii)(A) All.a

C 98.36(e)(2)(ii)(C) Only HHV value for each calendar month in which HHV determination is 

required.a

C 98.36(e)(2)(ii)(D) All.a

C 98.36(e)(2)(iv)(A) All.a

C 98.36(e)(2)(iv)(C) All.a

C 98.36(e)(2)(iv)(F) All.a

C 98.36(e)(2)(ix)(D) All.a

C 98.36(e)(2)(ix)(E) All.a

C 98.36(e)(2)(ix)(F) All.a

E 98.56(g) All.

E 98.56(h) All.

E 98.56(j)(4) All.

E 98.56(j)(5) All.

E 98.56(j)(6) All.

E 98.56(l) All.

H 98.86(b)(11) All.
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H 98.86(b)(13) Name of raw kiln feed or raw material.

O 98.156(d)(2) All.

O 98.156(d)(3) All.

O 98.156(d)(4) All.

Q 98.176(f)(1) All.

W 98.236(c)(1)(i) All.

W 98.236(c)(1)(ii) All.

W 98.236(c)(1)(iii) All.

W 98.236(c)(2)(i) All.

W 98.236(c)(3)(i) All.

W 98.236(c)(3)(ii) Only Calculation Methodology 2.

W 98.236(c)(3)(iii) All.

W 98.236(c)(3)(iv) All.

W 98.236(c)(4)(i)(A) All.

W 98.236(c)(4)(i)(B) All.

W 98.236(c)(4)(i)(C) All.

W 98.236(c)(4)(i)(D) All.

W 98.236(c)(4)(i)(E) All.

W 98.236(c)(4)(i)(F) All.

W 98.236(c)(4)(i)(G) All.

W 98.236(c)(4)(i)(H) All.

W 98.236(c)(4)(ii)(A) All.

W 98.236(c)(5)(i)(D) All.

W 98.236(c)(5)(ii)(C) All.

W 98.236(c)(6)(i)(B) All.b

W 98.236(c)(6)(i)(D) All.b

W 98.236(c)(6)(i)(E) All.b

W 98.236(c)(6)(i)(F) All.b

W 98.236(c)(6)(i)(G) Only the amount of natural gas required.

W 98.236(c)(6)(i)(H) Only the amount of natural gas required.

W 98.236(c)(6)(ii)(A) All.

W 98.236(c)(6)(ii)(B) All.

W 98.236(c)(7)(i)(A) Only for Equation W-14A.

W 98.236(c)(8)(i)(F) All.b
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W 98.236(c)(8)(i)(K) All.

W 98.236(c)(8)(ii)(A) All.b

W 98.236(c)(8)(ii)(H) All.

W 98.236(c)(8)(iii)(A) All.

W 98.236(c)(8)(iii)(B) All.

W 98.236(c)(8)(iii)(G) All.

W 98.236(c)(12)(ii) All.

W 98.236(c)(12)(v) All.

W 98.236(c)(13)(i)(E) All.

W 98.236(c)(13)(i)(F) All.

W 98.236(c)(13)(ii)(A) All.

W 98.236(c)(13)(ii)(B) All.

W 98.236(c)(13)(iii)(A) All.

W 98.236(c)(13)(iii)(B) All.

W 98.236(c)(13)(v)(A) All.

W 98.236(c)(14)(i)(B) All.

W 98.236(c)(14)(ii)(A) All.

W 98.236(c)(14)(ii)(B) All.

W 98.236(c)(14)(iii)(A) All.

W 98.236(c)(14)(iii)(B) All.

W 98.236(c)(14)(v)(A) All.

W 98.236(c)(15)(ii)(A) All.

W 98.236(c)(15)(ii)(B) All.

W 98.236(c)(16)(viii) All.

W 98.236(c)(16)(ix) All.

W 98.236(c)(16)(x) All.

W 98.236(c)(16)(xi) All.

W 98.236(c)(16)(xii) All.

W 98.236(c)(16)(xiii) All.

W 98.236(c)(16)(xiv) All.

W 98.236(c)(16)(xv) All.

W 98.236(c)(16)(xvi) All.

W 98.236(c)(17)(ii) All.

W 98.236(c)(17)(iii) All.
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W 98.236(c)(17)(iv) All.

W 98.236(c)(18)(i) All.

W 98.236(c)(18)(ii) All.

W 98.236(c)(19)(iv) All.

W 98.236(c)(19)(vii) All.

Y 98.256(h)(5)(i) Only value of the correction.

Y 98.256(k)(4) Only mole fraction of methane in coking gas.

Y 98.256(n)(3) All (if used in Equation Y-21 to calculate emissions from equipment leaks).

Y 98.256(o)(4)(vi) Only tank-specific methane composition data and gas generation rate data.

AA 98.276(e) All.

CC 98.296(b)(10)(i) All.

CC 98.296(b)(10)(ii) All.

CC 98.296(b)(10)(iii) All.

CC 98.296(b)(10)(iv) All.

CC 98.296(b)(10)(v) All.

CC 98.296(b)(10)(vi) All.

II 98.356(d)(2) All (if conducting weekly sampling).

II 98.356(d)(3) All (if conducting weekly sampling).

II 98.356(d)(4) Only weekly average temperature (if conducting weekly sampling).

II 98.356(d)(5) Only weekly average moisture content (if conducting weekly sampling).

II 98.356(d)(6) Only weekly average pressure (if conducting weekly sampling).

a Required to be reported only by: (1) Stationary fuel combustion sources (e.g., individual units, aggregations of 

units, common pipes, or common stacks) subject to subpart C of this part that contain at least one combustion 

unit connected to a fuel-fired electric generator owned or operated by an entity that is subject to regulation of 

customer billing rates by the PUC (excluding generators connected to combustion units subject to 40 CFR part 

98, subpart D) and that are located at a facility for which the sum of the nameplate capacities for all such 

electric generators is greater than or equal to 1 megawatt electric output; and (2) stationary fuel combustion 

sources (e.g., individual units, aggregations of units, common pipes, or common stacks) subject to subpart C of 

this part that do not meet the criteria in (1) of this footnote that elect to report these data elements, as provided 

in §98.36(a), for reporting year 2014.

b This rule citation provides an option to delay reporting of this data element for certain wildcat wells and/or 

delineation wells.