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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 and industrial GHG suppliers. For suppliers, the GHGs 

reported are the quantity that would be emitted from combustion 

or use of the products supplied.

(b) Owners and operators of facilities and suppliers that 

are subject to this part must follow the requirements of 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 
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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 in any calendar year 

starting in 2010. 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.

(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 CO 2 e 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.
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(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.

(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.
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(1) Calculate the annual emissions of CO2, CH4, N2O, and 

each fluorinated GHG in metric tons from all applicable source 

categories listed in paragraph (a)(2) of this section. The GHG 

emissions shall be calculated using the calculation 

methodologies specified in each applicable subpart and available 

company records. Include emissions from only those gases listed 

in Table A–1 of this subpart.

(2) For each general stationary fuel combustion unit, 

calculate the annual CO2 emissions in metric tons using any of 

the four calculation methodologies specified in §98.33(a). 

Calculate the annual CH4 and N2O emissions from the stationary 

fuel combustion sources in metric tons using the appropriate 

equation in §98.33(c). Exclude carbon dioxide emissions from the 

combustion of biomass, but include emissions of CH4 and N2O from 

biomass combustion.

(3) For miscellaneous uses of carbonate, calculate the 

annual CO2 emissions in metric tons using the procedures 

specified in subpart U of this part.

(4) Sum the emissions estimates from paragraphs (b)(1), 

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

metric tons of CO2e using Equation A–1 of this section.

Where:
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CO2 e = Carbon dioxide equivalent, metric tons/year.

GHGi = Mass emissions of each greenhouse gas listed 

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

GWPi = Global warming potential for each greenhouse 

gas from Table A–1 of this subpart.

n = The number of greenhouse gases emitted.

(5) For purpose of determining if an emission threshold has 

been exceeded, include in the emissions calculation any CO2 that 

is captured for transfer off site.

(c) To calculate GHG emissions for comparison to the 25,000 

metric ton CO2 e/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 
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threshold. Calculate the emissions using the methodology 

specified in subpart LL of this part.

(e) To calculate GHG quantities for comparison to the 

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

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

section, calculate the mass in metric tons per year of CO2 that 

would result from the complete combustion or oxidation of the 

volume of petroleum products and natural gas liquids that are 

imported during the reporting year and that are exported during 

the reporting year. Compare the imported quantities and the 

exported quantities separately to the 25,000 metric ton CO2 per 

year threshold. Calculate the emissions using the methodology 

specified in subpart MM of this part.

(f) To calculate GHG quantities for comparison to the 

25,000 metric ton CO2e per year threshold under paragraph (a)(4) 

of this section for importers and exporters of industrial 

greenhouse gases and for importers and exporters of CO2,the 

owner or operator shall calculate the mass in metric tons per 

year of CO2e imports and exports as described in paragraphs 

(f)(1) through (f)(3) of this section. 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 
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tons per year of CO2, N2O, and each fluorinated GHG that is 

exported during the year. Include only those gases listed in 

Table A–1 of this subpart.

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

from paragraph (f)(1) of this section to metric tons of CO2e 

using Equation A–1 of this section.

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

(f)(2) of this section for all imported GHGs. Sum the total 

annual metric tons of CO2e in paragraph (f)(2) of this section 

for all exported GHGs.

(g) If a capacity or generation reporting threshold in 

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

shall review the appropriate records and perform any necessary 

calculations to determine whether the threshold has been 

exceeded.

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

does not meet the applicability requirements of paragraph (a) of 

this section is not subject to this rule. Such owner or operator 

would become subject to the rule and reporting requirements, 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 
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there is any change that could cause a facility or supplier to 

meet the applicability requirements of paragraph (a) of this 

section. Such changes include but are not limited to process 

modifications, increases in operating hours, increases in 

production, changes in fuel or raw material use, addition of 

equipment, and facility expansion.

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

or supplier is subject to the requirements of this part, the 

owner or operator must continue for each year thereafter to 

comply with all requirements of this part, including the 

requirement to submit annual GHG reports, even if the facility 

or supplier does not meet the applicability requirements in 

paragraph (a) of this section in a future year.

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

CO2e per year for five consecutive years, then the owner or 

operator may discontinue complying with this part provided that 

the owner or operator submits a notification to the 

Administrator that announces the cessation of reporting and 

explains the reasons for the reduction in emissions. The 

notification shall be submitted no later than March 31 of the 

year immediately following the fifth consecutive year of 

emissions less than 25,000 tons CO2e per year. The owner or 

operator must maintain the corresponding records required under 

§98.3(g) for each of the five consecutive years and retain such 
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records for three years following the year that reporting was 

discontinued. The owner or operator must resume reporting if 

annual emissions in any future calendar year increase to 25,000 

metric tons CO2e per year or more.

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

CO2e per year for three consecutive years, then the owner or 

operator may discontinue complying with this part provided that 

the owner or operator submits a notification to the 

Administrator that announces the cessation of reporting and 

explains the reasons for the reduction in emissions. The 

notification shall be submitted no later than March 31 of the 

year immediately following the third consecutive year of 

emissions less than 15,000 tons CO2e per year. The owner or 

operator must maintain the corresponding records required under 

§98.3(g) for each of the three consecutive years and retain such 

records for three years following the year that reporting was 

discontinued. The owner or operator must resume reporting if 

annual emissions in any future calendar year increase to 25,000 

metric tons CO2e per year or more.

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

such that all applicable GHG-emitting processes and operations 

listed in paragraphs (a)(1) through (a)(4) of this section cease 

to operate, then the owner or operator is exempt from reporting 

in the years following the year in which cessation of such 
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operations occurs, provided that the owner or operator submits a 

notification to the Administrator that announces the cessation 

of reporting and certifies to the closure of all GHG-emitting 

processes and operations 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. The owner or operator must resume 

reporting for any future calendar year during which any of the 

GHG-emitting processes or operations resume operation.

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

for some of the common units of measure used in part 98.

§ 98.3 What are the general monitoring, reporting, recordkeeping 

and verification requirements of this part?

The owner or operator of a facility or supplier that is 

subject to the requirements of this part must submit GHG reports 

to the Administrator, as specified in this section.

(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.
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(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 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).
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(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 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 
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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 
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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 this 

subpart. For electronics manufacturing (as defined in §98.90), 

starting in reporting year 2012 the CO2e calculation must include 

each fluorinated heat 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)(E) of this 

section.

(A) Biogenic CO2.

(B) CO2 (excluding biogenic CO2).

(C) CH4.

(D) N2O.

(E) Each fluorinated GHG (as defined in §98.6), including 

those not listed in Table A–1 of this subpart.

(F) For electronics manufacturing (as defined in § 98.90), 

each fluorinated heat transfer fluid (as defined in § 98.98) 
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that is not also a fluorinated GHG as specified under 

(c)(4)(iii)(E) of this section. This requirement applies 

beginning in reporting year 2012.

(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) When applying paragraph (c)(4)(i) of this section to 

fluorinated GHGs and fluorinated heat transfer fluids, calculate 

and report CO2e for only those fluorinated GHGs listed in Table 

A–1 of this subpart.

(vii) The owner or operator of a facility is not required 

to report the data elements specified in Table A–6 to 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 to this subpart 

for calendar years 2010 through 2013 until March 31, 2015.

(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 
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categories listed in Table A–3 and Table A–4 of this subpart 

present at the facility.

(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. For fluorinated GHGs, calculate and report CO2e for 

only those fluorinated GHGs listed in Table A–1 of this subpart.

(ii) Quantity of each GHG from each applicable supply 

category in Table A–5 of this subpart, expressed in metric tons 

of each GHG. For fluorinated GHG, report quantities of all 

fluorinated GHG, including those not listed in Table A-1 to this 

subpart. 

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

requirements” section of each applicable subpart of this part.

(6) A written explanation, as required under §98.3(e), if 

you change emission calculation methodologies during the 

reporting period.

(7) A brief description of each “best available monitoring 

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

was used, if applicable.

(8) Each data element for which a missing data procedure 

was used according to the procedures of an applicable subpart 

and the total number of hours in the year that a missing data 

procedure was used for each data element.

(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 reporting entity'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 highestlevel United States parent company(s) of the owners (or 

operators) of the facility or supplier and the percentage of 
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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.

(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 
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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.

(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 
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§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.
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(D) N2O.

(E) Each fluorinated GHG (including those not listed in 

Table A–1 of this subpart).

(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) 
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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 an relevant subpart.

(ii) Supplier data.

(iii) Engineering calculations.

(iv) Other company records.

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

monitoring methods. The owner or operator may submit a request 

to the Administrator to use one or more best available 

monitoring methods beyond March 31, 2010.

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

submitted to EPA no later than 30 days after the effective date 

of the GHG reporting rule.

(ii) Content of request. Requests must contain the 

following information:

(A) A list of specific item of monitoring instrumentation 

for which the request is being made and the locations where each 

piece of monitoring instrumentation will be installed.

(B) Identification of the specific rule requirements (by 

rule subpart, section, and paragraph numbers) for which the 

instrumentation is needed.

(C) A description of the reasons why the needed equipment 

could not be obtained and installed before April 1, 2010.
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(D) If the reason for the extension is that the equipment 

cannot be purchased and delivered by April 1, 2010, include 

supporting documentation such as the date the monitoring 

equipment was ordered, investigation of alternative suppliers 

and the dates by which alternative vendors promised delivery, 

backorder notices or unexpected delays, descriptions of actions 

taken to expedite delivery, and the current expected date of 

delivery.

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

cannot be installed without a process unit shutdown, include 

supporting documentation demonstrating that it is not 

practicable to isolate the equipment and install the monitoring 

instrument without a full process unit shutdown. Include the 

date of the most recent process unit shutdown, the frequency of 

shutdowns for this process unit, and the date of the next 

planned shutdown during which the monitoring equipment can be 

installed. If there has been a shutdown or if there is a planned 

process unit shutdown between promulgation of this part and 

April 1, 2010, include a justification of why the equipment 

could not be obtained and installed during that shutdown.

(F) A description of the specific actions the facility will 

take to obtain and install the equipment as soon as reasonably 

feasible and the expected date by which the equipment will be 

installed and operating.
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(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 
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method specified in §98.33(a) and expressed in metric tons of 

CO2,CH4,N2O, and CO2 e.

(v) Any facility operating data or process information used 

for the GHG emission calculations.

(vi) A signed and dated certification statement provided by 

the designated representative of the owner or operator, 

according to the requirements of paragraph (e)(1) of this 

section.

(e) Emission calculations. In preparing the GHG report, you 

must use the calculation methodologies specified in the relevant 

subparts, except as specified in paragraph (d) of this section. 

For each source category, you must use the same calculation 

methodology throughout a reporting period unless you provide a 

written explanation of why a change in methodology was required.

(f) Verification. To verify the completeness and accuracy 

of reported GHG emissions, the Administrator may review the 

certification statements described in paragraphs (c)(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.
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(g) Recordkeeping. An owner or operator that is required to 

report GHGs under this part must keep records as specified in 

this paragraph. Retain all required records for at least 3 

years. 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. 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):
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(i) The GHG emissions calculations and methods used.

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

(iii) The results of all required analyses for high heat 

value, carbon content, and other required fuel or feedstock 

parameters.

(iv) Any facility operating data or process information 

used for the GHG emission calculations.

(3) The annual GHG reports.

(4) Missing data computations. For each missing data event, 

also retain a record of the 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.
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(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.

(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.
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(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 (h)(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 (h)(2) of this section. If the 

Administrator receives a request for extension of the 45-day 

period, by e-mail 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 at least 5 business days 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 (h)(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 (h)(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.
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(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 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 
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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.

(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 
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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., 
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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.

(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 
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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; 

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 
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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 
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the GHG Monitoring Plan. You must maintain all of this 

information in a format suitable for auditing and inspection.

(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 
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(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 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 
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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 monitoring methods beyond 

December 31, 2010 (or an earlier date approved by EPA) in cases 

where measurement device installation would require a process 
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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.
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(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 

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 
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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 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 
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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 provision 

for reporting year 2013. This paragraph (k) 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.

(1) A facility or supplier that was not subject to any

subpart of part 98 for reporting year 2012, but first becomes

subject to any subpart of 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 reporting year 2013.

(2) A facility or supplier that is subject to a subpart of 

part 98 for reporting year 2012, but first becomes subject to 

any subpart of part 98 due to a change in the GWP for one or 

more compounds in Table A-1 of this subpart, is not required to 
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include those subparts for which the facility is subject only 

due to the change in the GWP in the annual GHG report submitted 

for reporting year 2013. 

(3) Starting on January 1, 2014, facilities or suppliers 

identified in paragraphs (k)(1) or (k)(2) of this section must 

start monitoring and collecting GHG data in compliance with the 

applicable subparts of part 98 for which the facility is subject 

due to the change in the GWP for the annual greenhouse gas 

report for reporting year 2014, which is due by March 31, 2015.

(l) Special provision for best available monitoring 

methods in 2014. 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, 2014 

to March 31, 2014, owners or operators subject to this paragraph 

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 
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required piece of monitoring equipment by January 1, 2014. 

Starting no later than April 1, 2014, 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 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, 2014.

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

submitted to EPA no later than January 31, 2014.

(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.
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(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, 2014.

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

cannot be purchased and delivered by April 1, 2014, 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 [INSERT THE DATE OF PUBLICATION OF 

THE FINAL RULE IN THE FEDERAL REGISTER] and April 1, 2014, 
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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, 

2014. The use of best available methods under this paragraph (l) 

will not be approved beyond December 31, 2014.

§ 98.4 Authorization and responsibilities of the designated 

representative.

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

section, each facility, and each supplier, that is subject to 

this part, shall have one and only one designated 

representative, who shall be responsible for certifying, 

signing, and submitting GHG emissions reports and any other 

submissions for such facility and supplier respectively to the 

Administrator under this part. If the facility is required under 

any other part of title 40 of the Code of Federal Regulations to 

submit to the Administrator any other emission report that is 

subject to any requirement in 40 CFR part 75, the same 
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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 
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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 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 
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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.

(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 
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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 
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elements in a format prescribed by the Administrator in 

accordance with this section:

(1) Identification of the facility or supplier for which 

the certificate of representation is submitted.

(2) The name, organization name (company affiliationemployer), 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, 
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as applicable, and that each such owner and operator shall be 

fully bound by my representations, actions, inactions, or 

submissions.”

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

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

issued to me by the Administrator or a court regarding the 

facility or supplier.”

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

facility or supplier, as applicable, I certify that I have given 

a written notice of my selection as the `designated 

representative' or `alternate designated representative', as 

applicable, and of the agreement by which I was selected to each 

owner and operator of the facility or supplier.”

(5) The signature of the designated representative and any 

alternate designated representative and the dates signed.

(j) Documents of agreement. Unless otherwise required by 

the Administrator, documents of agreement 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 
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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.

(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 
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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 affiliationemployer) 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 
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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) of 

this section shall be deemed to be an electronic submission 

certified, signed, and submitted by the designated 

representative or alternate designated representative submitting 

such notice of delegation.

§ 98.5 How is the report submitted?

Each GHG report and certificate of representation for a 

facility or supplier must be submitted electronically in 

accordance with the requirements of §98.4 and in a format 

specified by the Administrator.

§ 98.6 Definitions.

All terms used in this part shall have the same meaning 

given in the Clean Air Act and in this section.

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

percent of full scale or one percent of the value measured)

means that the mean of repeat measurements made by a device or 

technique are within 95 percent of the range bounded by the true 

value plus or minus the specified level.

Acid Rain Program means the program established under title 

IV of the Clean Air Act, and implemented under parts 72 through 

78 of this chapter for the reduction of sulfur dioxide and 

nitrogen oxides emissions.

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 
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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 

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.
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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 nonfossilized 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.
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Blendstocks are petroleum products used for blending or 

compounding into finished motor gasoline. These include RBOB 

(reformulated blendstock for oxygenate blending) and CBOB 

(conventional blendstock for oxygenate blending), but exclude 

oxygenates, butane, and pentanes plus.

Blendstocks—Others are products used for blending or 

compounding into finished motor gasoline that are not defined 

elsewhere. Excludes Gasoline Treated as Blendstock (GTAB), 

Diesel Treated as Blendstock (DTAB), conventional blendstock for 

oxygenate blending (CBOB), reformulated blendstock for oxygenate 

blending (RBOB), oxygenates (e.g. 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 shut-down (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, 
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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.

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 
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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.

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 
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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 
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carbonate (Li2CO3); and for strontium carbonate, the mass 

fraction of strontium carbonate (SrCO3).

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.

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 
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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.

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 
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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.

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.
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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.

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.
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Coke burn-off means the coke removed from the surface of a 

catalyst by combustion during catalyst regeneration. Coke burnoff 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 
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or piece of equipment. A common connector is a flange. Joined 

fittings welded completely around the circumference of the 

interface are not considered connectors for the purpose of this 

part.

Container glass means glass made of soda-lime recipe, clear 

or colored, which is pressed and/or blown into bottles, jars, 

ampoules, and other products listed in North American Industry 

Classification System 327213 (NAICS 327213).

Continuous 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 
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maintenance, malfunction, control device installation, 

reconstruction, or rebuilding.

Conventional-Summer refers to finished gasoline formulated 

for use in motor vehicles, the composition and properties of 

which do not meet the requirements of the reformulated gasoline 

regulations promulgated by the U.S. Environmental Protection 

Agency under 40 CFR 80.40, but which meet summer RVP standards 

required under 40 CFR 80.27 or as specified by the 

state.Note:This category excludes conventional gasoline for 

oxygenate blending (CBOB) as well as other blendstock.

Conventional-Winter refers to finished gasoline formulated 

for use in motor vehicles, the composition and properties of 

which do not meet the requirements of the reformulated gasoline 

regulations promulgated by the U.S. Environmental Protection 

Agency under 40 CFR 80.40 or the summer RVP standards required 

under 40 CFR 80.27 or as specified by the state.Note:This 

category excludes conventional blendstock for oxygenate blending 

(CBOB) as well as other blendstock.

Crude oil means a mixture of hydrocarbons that exists in 

liquid phase in natural underground reservoirs and 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:
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(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.

Daily spread means a manure management system component in 

which manure is routinely removed from a confinement facility 
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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.
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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.

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 
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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 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.
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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.”

Direct liquefaction means the conversion of coal directly 

into liquids, rather than passing through an intermediate 

gaseous state.
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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 
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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.

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 
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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.

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.
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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 nonexperimental 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 
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emits or may emit any greenhouse gas. Operators of military 

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.
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Flat glass means glass made of soda-lime recipe and 

produced into continuous flat sheets and other products listed 

in NAICS 327211.

Flowmeter means a device that measures the mass or 

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

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

are not limited to, rotameters, turbine meters, coriolis meters, 

orifice meters, ultra-sonic flowmeters, and vortex flowmeters).

Fluid coking unit means one or more refinery process units 

in which high molecular weight petroleum derivatives are 

thermally cracked and petroleum coke is continuously produced in 

a fluidized bed system. The fluid coking unit includes equipment 

for controlling air pollutant emissions and for heat recovery on 

the fluid coking burner exhaust vent. There are two basic types 

of fluid coking units: A traditional fluid coking unit in which 

only a small portion of the coke produced in the unit is burned 

to fuel the unit and the fluid coking burner exhaust vent is 

directed to the atmosphere (after processing in a CO boiler or 

other air pollutant control equipment) and a flexicoking unit in 

which an auxiliary burner is used to partially combust a 

significant portion of the produced petroleum coke to generate a 

low value fuel gas that is used as fuel in other combustion 

sources at the refinery.
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Fluorinated greenhouse gas means sulfur hexafluoride (SF6), 

nitrogen trifluoride (NF3), and any fluorocarbon except for 

controlled substances as defined at 40 CFR part 82, subpart A 

and substances with vapor pressures of less than 1 mm of Hg 

absolute at 25 degrees C. With these exceptions, “fluorinated 

GHG” includes but is not limited to any hydrofluorocarbon, any 

perfluorocarbon, any fully fluorinated linear, branched or 

cyclic alkane, ether, tertiary amine or aminoether, any 

perfluoropolyether, and any hydrofluoropolyether.

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

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

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 

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.
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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.

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 to a single location for treatment 

(thermal destruction) or use. Landfill gas collection systems 

may also include knock-out or separator drums and/or a 

compressor. A single landfill may have multiple gas collection 

systems. Landfill gas collection systems do not include 
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“passive” systems, whereby landfill gas flows naturally to the 

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

installed to allow for natural gas flow.

Gas 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 refractorylined vessel in which raw materials are charged and melted at 

high temperature to produce molten glass.

Glass produced means the weight of glass exiting a glass 

melting furnace.

Global warming potential or GWP means the ratio of the 

time-integrated radiative forcing from the instantaneous release 

of one kilogram of a trace substance relative to that of one 

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

GPA means the Gas Processors Association.

Greenhouse gas or GHG means carbon dioxide (CO2), methane 

(CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), 

hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and other 

fluorinated greenhouse gases as defined in this section.

GTBA (gasoline-grade tertiary butyl alcohol, (CH3)3COH), or 

t-butanol, is an alcohol as described in “Oxygenates.”

Heavy Gas Oils are petroleum distillates with an 

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

Heel means the amount of gas that remains in a shipping 

container after it is discharged or off-loaded (that is no more 

than ten percent of the volume of the container).

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 
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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 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.
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(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, 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 
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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 snapacting 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.

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 
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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.

Lime is the generic term for a variety of chemical 

compounds that are produced by the calcination of limestone or 
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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 
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carbon source typically at thermophilic temperatures produced by 

microbial heat production. There are four types of composting 

employed for manure management: Static, in vessel, intensive 

windrow and passive windrow. Static composting typically occurs 

in an enclosed channel, with forced aeration and continuous 

mixing. In vessel composting occurs in piles with forced 

aeration but no mixing. Intensive windrow composting occurs in 

windrows with regular turning for mixing and aeration. Passive 

windrow composting occurs in windrows with infrequent turning 

for mixing and aeration.

Maximum rated heat input capacity means the hourly heat 

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

amount of fuel per hour that it is capable of 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.
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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 ReformulatedWinter. For midgrade categories of RBOB-Summer, RBOB-Winter, 

CBOB-Summer, and CBOB-Winter, this definition refers to the 

expected octane rating of the finished gasoline after oxygenate 

has been added to the RBOB or CBOB.

Miscellaneous products include all refined petroleum 

products not defined elsewhere. It includes, but is not limited 

to, naphtha-type jet fuel (Jet B and JP–4), petrolatum lube 

refining by-products (aromatic extracts and tars), absorption 

oils, ram-jet fuel, petroleum rocket fuels, synthetic natural 

gas feedstocks, waste feedstocks, and specialty oils. It 

excludes organic waste sludges, tank bottoms, spent catalysts, 

and sulfuric acid.
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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 

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.
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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, refuse-derived 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 
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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 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 
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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.

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 by-products are not recovered.

North American Industry Classification System (NAICS) 

code(s) means the six-digit code(s) that represents the 
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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 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), 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.
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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.
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Petroleum product means all refined and semi-refined 

products that are produced at a refinery by processing crude oil 

and other petroleum-based feedstocks, including petroleum 

products derived from co-processing biomass and petroleum 

feedstock together, but not including plastics or plastic 

products. Petroleum products may be combusted for energy use, or 

they may be used either for non-energy processes or as nonenergy 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 
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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.

(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, 
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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 ReformulatedWinter. For premium grade categories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOB-Winter, this definition refers to 

the expected octane rating of the finished gasoline after 

oxygenate has been added to the RBOB or CBOB.

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 
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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 inline 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 
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from feed materials, it is also, by definition, a raw material 

dryer. The raw mill also includes the air separator associated 

with the raw mill.

RBOB-Summer (reformulated blendstock for oxygenate 

blending) means a petroleum product which, when blended with a 

specified type and percentage of oxygenate, meets the definition 

of Reformulated-Summer.

RBOB-Winter (reformulated blendstock for oxygenate 

blending) means a petroleum product which, when blended with a 

specified type and percentage of oxygenate, meets the definition 

of Reformulated-Winter.

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.
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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 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, ReformulatedSummer, and Reformulated-Winter. For regular 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.

Rendered animal fat, or tallow, means fats extracted from 

animals which are generally used as a feedstock in making 

biodiesel.

Research and development means those activities conducted 

in process units or at laboratory bench-scale settings whose 

purpose is to conduct research and development for new 

processes, technologies, or products and whose purpose is not 

for the manufacture of products for commercial sale, except in a 

de minimis manner.

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

for the heavier fuel oil generally used in steam powered vessels 

in government service and inshore power plants. It has a minimum 

flash point of 131 °F.

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

classification for the heavier fuel oil generally used for the 

production of electric power, space heating, vessel bunkering 

and various industrial purposes. It has a minimum flash point of 

140 °F.

Residuum is residue from crude oil after distilling off all 

but the heaviest components, with a boiling range greater than 

1,000 °F.
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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 
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requirements for the safe handling of flammable, combustible, 

explosive, reactive, or hazardous materials.

Sales oil means produced crude oil or condensate measured 

at the production lease automatic custody transfer (LACT) meter 

or custody transfer tank gauge.

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.
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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.

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 
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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.

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.
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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 of 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 
Page 118 of 168

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).

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.

Unstabilized crude oil means, for the purposes of this 

part, crude oil that is pumped from the well to a pipeline or 
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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.
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Vegetable oil means oils extracted from vegetation that are 

generally used as a feedstock in making biodiesel.

Ventilation hole or shaft means a vent hole or shaft 

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 zinccontaining 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 
Page 121 of 168

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 flowback of injected gas, water, oil, and proppant 

used to fracture or re-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 re-fracture and prop-open new 

fractures in existing low permeability gas reservoirs, steps 

that may vent large quantities of produced gas to the 

atmosphere.
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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, telephone and utility poles, pier and 
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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 zincbearing feed materials charged to a furnace.

§ 98.7 What standardized methods are incorporated by reference 

into this part?
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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 theFederal Register.The materials are 

available for purchase at the corresponding address in this 

section. The materials are available for inspection at the EPA 

Docket Center, Public Reading Room, EPA West Building, Room 

3334, 1301 Constitution Avenue, NW., Washington, DC, phone (202) 

566–1744 and at the National Archives and Records Administration 

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

NARA, call 202–741–6030, or go to: 

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

ions/ibr_locations.html.

(a) [Reserved]

(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).
Page 125 of 168

(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).

(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).
Page 126 of 168

(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).
Page 127 of 168

(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).
Page 128 of 168

(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).

(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 HighPurity 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).
Page 129 of 168

(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).

(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 
Page 130 of 168

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).

(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), §98.124(e)(2), §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).
Page 131 of 168

(32) ASTM D6751–08 Standard Specification for Biodiesel 

Fuel Blend Stock (B100) for Middle Distillate Fuels, IBR 

approved for §98.6.

(33) ASTM D6866–08 Standard Test Methods for Determining 

the Biobased Content of Solid, Liquid, and Gaseous Samples Using 

Radiocarbon Analysis, IBR approved for §98.34(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]
Page 132 of 168

(40) ASTM E1915–07a Standard Test Methods for Analysis of 

Metal Bearing Ores and Related Materials by Combustion InfraredAbsorption 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 Pressure-Temperature Relationship and Initial 

Decomposition Temperature of Liquids by Isoteniscope (ASTM 

D2879), approved May 1, 2007, IBR approved for §98.128.
Page 133 of 168

(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).

(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 
Page 134 of 168

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).

(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).
Page 135 of 168

(2) [Reserved]

(i) The following material is available for purchase from 

the National Institute of Standards and Technology (NIST), 100 

Bureau Drive, Stop 1070, Gaithersburg, MD 20899–1070, (800) 877–

8339, http://www.nist.gov/index.html.

(1) Specifications, Tolerances, and Other Technical 

Requirements For Weighing and Measuring Devices, NIST Handbook 

44 (2009), incorporation by reference (IBR) approved for 

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

(2) [Reserved]

(j) The following material is available for purchase from 

the Technical Association of the Pulp and Paper Industry 

(TAPPI), 15 Technology Parkway South, Norcross, GA 30092, (800) 

332–8686, http://www.tappi.org.

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

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

§98.277(d).

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

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

(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, 
Page 136 of 168

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) General Coal Mine Inspection Procedures and Inspection 

Tracking System, Handbook Number: PH–08–V–1, January 1, 2008, 

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).
Page 137 of 168

(3) Protocol for Measuring Destruction or Removal 

Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement 

Equipment in Electronics Manufacturing, Version 1, EPA–430–R–10–

003, March 2010 (EPA 430–R–10–003), 

http://www.epa.gov/semiconductor-pfc/documents/dre_protocol.pdf,

IBR approved for §98.94(f)(4)(i), §98.94(g)(3), §98.97(d)(4), 

§98.98, §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).
Page 138 of 168

(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).

(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), 
Page 139 of 168

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).

(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).
Page 140 of 168

(n) [Reserved]

(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/current/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?
Page 141 of 168

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.
Page 142 of 168

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.)

Carbon dioxide 124–38–9CO2 1

Methane 74–82–8CH4 25

a

Nitrous oxide 10024–97–2N2O 298a

HFC–23 75–46–7CHF3 14,800a

HFC–32 75–10–5CH2F2 675a

HFC–41 593–53–3CH3F 92a

HFC–125 354–33–6C2HF5 3,500a

HFC–134 359–35–3C2H2F4 1,100a

HFC–134a 811–97–2CH2FCF3 1,430a

HFC–143 430–66–0C2H3F3 353a

HFC–143a 420–46–2C2H3F3 4,470a

HFC–152 624–72–6CH2FCH2F 53

HFC–152a 75–37–6CH3CHF2 124a

HFC–161 353–36–6CH3CH2F 12

HFC–227ea 431–89–0C3HF7 3,220a

HFC–236cb 677–56–5CH2FCF2CF3 1,340

HFC–236ea 431–63–0CHF2CHFCF3 1,370

HFC–236fa 690–39–1C3H2F6 9,810a

HFC–245ca 679–86–7C3H3F5 693a

HFC–245fa 460–73–1CHF2CH2CF3 1,030

HFC–365mfc 406–58–6CH3CF2CH2CF3 794

HFC–43–10mee 138495–42–8CF3CFHCFHCF2CF3 1,640a

Sulfur hexafluoride 2551–62–4SF6 22,800a

Trifluoromethyl sulphur 

pentafluoride

373–80–8SF5CF3 17,700

Nitrogen trifluoride 7783–54–2NF3 17,200
Page 143 of 168

Name CAS No.

Chemical 

formula

Global 

warming 

potential

(100 yr.)

PFC–14 

(Perfluoromethane)

75–73–0CF4 7,390a

PFC–116 

(Perfluoroethane)

76–16–4C2F6 12,200a

PFC–218 

(Perfluoropropane)

76–19–7C3F8 8,830a

Perfluorocyclopropane 931–91–9C-C3F6 17,340

PFC–3–1–10 

(Perfluorobutane)

355–25–9C4F10 8,860a

Perfluorocyclobutane 115–25–3C-C4F8 10,300a

PFC–4–1–12 

(Perfluoropentane)

678–26–2C5F12 9,160a

PFC–5–1–14

(Perfluorohexane)

355–42–0C6F14 9,300a

PFC–9–1–18 306–94–5C10F18 7,500

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

HFE–43–10pccc (H–Galden 

1040x)

E1730133CHF2OCF2OC2F4OCH

F2

1,870

HFE–125 3822–68–2CHF2OCF3 14,900

HFE–134 1691–17–4CHF2OCHF2 6,320

HFE–143a 421–14–7CH3OCF3 756

HFE–227ea 2356–62–9CF3CHFOCF3 1,540

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

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

HFE–236fa 20193–67–3CF3CH2OCF3 487

HFE–245cb2 22410–44–2CH3OCF2CF3 708

HFE–245fa1 84011–15–4CHF2CH2OCF3 286

HFE–245fa2 1885–48–9CHF2OCH2CF3 659

HFE–254cb2 425–88–7CH3OCF2CHF2 359

HFE–263fb2 460–43–5CF3CH2OCH3 11
Page 144 of 168

Name CAS No.

Chemical 

formula

Global 

warming 

potential

(100 yr.)

HFE-329mcc2 67490-36-2 CF3CF2OCF2CHF2 919

HFE–338mcf2 156053–88–2CF3CF2OCH2CF3 552

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

HFE–347mcc3 28523–86–6CH3OCF2CF2CF3 575

HFE–347mcf2 E1730135CF3CF2OCH2CHF2 374

HFE–347pcf2 406–78–0CHF2CF2OCH2CF3 580

HFE–356mec3 382–34–3CH3OCF2CHFCF3 101

HFE–356pcc3 160620–20–2CH3OCF2CF2CHF2 110

HFE–356pcf2 E1730137CHF2CH2OCF2CHF2 265

HFE–356pcf3 35042–99–0CHF2OCH2CF2CHF2 502

HFE–365mcf3 378–16–5CF3CF2CH2OCH3 11

HFE–374pc2 512–51–6CH3CH2OCF2CHF2 557

HFE–449s1 (HFE–7100)

Chemical blend

163702–07–6

163702–08–7

C4F9OCH3

(CF3)2CFCF2OCH3

297

HFE–569sf2 (HFE–7200)

Chemical blend

163702–05–4

163702–06–5

C4F9OC2H5

(CF3)2CFCF2OC2H5

59

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

HFE–356mm1 13171–18–1(CF3)2CHOCH3 27

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

(Octafluorotetramethylene)hydroxymethyl groupNAX-(CF2)4CH(OH)-X 73

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

Bis(trifluoromethyl)-

methanol

920–66–1(CF3)2CHOH 195

2,2,3,3,3-

pentafluoropropanol

422–05–9CF3CF2CH2OH 42

PFPMIE NACF3OCF(CF3)CF2OC

F2OCF3

10,300
Page 145 of 168

a The GWP for this compound is different than the GWP in the 

version of Table A-1 to subpart A of part 98 published on 

October 30, 2009.

NA – Not available

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

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
Page 146 of 168

To convert from To Multiply by

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—Source Category List for §98.2(a)(1)

Source CategoriesaApplicable in 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).

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).
Page 147 of 168

Source CategoriesaApplicable in 2010 and Future Years

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 CategoriesaApplicable in 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).

aSource categories are defined in each applicable subpart.

Table A–4 to Subpart A of Part 98—Source Category List for 

§98.2(a)(2)

Source CategoriesaApplicable in 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).
Page 148 of 168

Zinc production (subpart GG).

Additional Source CategoriesaApplicable in 2011 and Future Years

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).

aSource categories are defined in each applicable subpart.

Table A–5 to Subpart A of Part 98—Supplier Category List for 

§98.2(a)(4)

Supplier CategoriesaApplicable in 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.
Page 149 of 168

Industrial greenhouse gas suppliers (subpart OO):

(A) All producers of industrial greenhouse gases.

(B) Importers of industrial greenhouse gases with 

annual bulk imports of N2O, fluorinated GHG, and CO2

that in combination are equivalent to 25,000 metric 

tons CO2e or more.

(C) Exporters of industrial greenhouse gases with 

annual bulk exports of N2O, fluorinated GHG, and CO2

that in combination are equivalent to 25,000 metric 

tons CO2e or more.

Carbon dioxide suppliers (subpart PP):

(A) All producers of CO2.

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

fluorinated GHG, and CO2 that in combination are 

equivalent to 25,000 metric tons CO2e or more.

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

fluorinated GHG, and CO2 that in combination are 

equivalent to 25,000 metric tons CO2e or more.

Additional Supplier Categories Applicableain 2011 and Future 

Years

Importers and exporters of fluorinated greenhouse gases 

contained in pre-charged equipment or closed-cell foams 

(subpart QQ):

(A) Importers 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.

(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.

aSuppliers are defined in each applicable subpart.
Page 150 of 168

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.

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.
Page 151 of 168

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)

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.
Page 152 of 168

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)

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 location.

HH 98.346(i)(9) Only CH4 generation value.

II 98.356(b)(1) All.

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.
Page 153 of 168

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)

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.

TT 98.466(c)(4)(ii) All.
Page 154 of 168

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)

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.

C 98.36(b)(9)(iii) Only estimate of the heat input.

C 98.36(c)(2)(ix) Only estimate of the heat input from 

each type of fuel listed in Table C–

2.

C 98.36(e)(2)(i) All.

C 98.36(e)(2)(ii)(A) All.

C 98.36(e)(2)(ii)(C) Only HHV value for each calendar 

month in which HHV determination is 

required.

C 98.36(e)(2)(ii)(D) All.
Page 155 of 168

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)

C 98.36(e)(2)(iv)(A) All.

C 98.36(e)(2)(iv)(C) All.

C 98.36(e)(2)(iv)(F) All.

C 98.36(e)(2)(ix)(D) All.

C 98.36(e)(2)(ix)(E) All.

C 98.36(e)(2)(ix)(F) All.

E 98.56(b) All.

E 98.56(c) All.

E 98.56(g) All.

E 98.56(h) All.

E 98.56(j)(1) All.

E 98.56(j)(3) All.

E 98.56(j)(4) All.

E 98.56(j)(5) All.

E 98.56(j)(6) All.

E 98.56(l) All.

F 98.66(a) All.

F 98.66(c)(2) All.

F 98.66(c)(3) Only smelter-specific slope 

coefficients and overvoltage 

emission factors.

F 98.66(e)(1) Only annual anode consumption (No 

CEMS).

F 98.66(f)(1) Only annual paste consumption (No 

CEMS).

F 98.66(g) All.

G 98.76(b)(2) All.

G 98.76(b)(7) All.
Page 156 of 168

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)

G 98.76(b)(8) All.

G 98.76(b)(9) All.

G 98.76(b)(10) All.

G 98.76(b)(11) All.

H 98.86(b)(2) All.

H 98.86(b)(5) All.

H 98.86(b)(6) All.

H 98.86(b)(8) All.

H 98.86(b)(10) All.

H 98.86(b)(11) All.

H 98.86(b)(12) All.

H 98.86(b)(13) All.

H 98.86(b)(15) Only monthly kiln-specific clinker 

factors (if used) for each kiln.

I 98.96(f)(1) All.

I 98.96(g) Only annual consumption of the gas 

(excluding annual consumption of 

gases for which the reporter did not 

calculate emissions using Equations 

I–6, I–7, I–8, I–9, and I–10 of 

subpart L).

I 98.96(h) All.

I 98.96(i) All.

I 98.96(j) All.

I 98.96(k) All.

I 98.96(l) All.

I 98.96(n) All.

I 98.96(o) All.

I 98.96(q)(2) Only inputs and results of 
Page 157 of 168

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)

calculations made accounting for the 

uptime of abatement systems used 

during the reporting year.

I 98.96(q)(3) All.

I 98.96(q)(5)(iv) Only inputs used to calculate the 

class average.

I 98.96(r) All.

I 98.96(s) Only estimates of inputs into the 

heat transfer fluid mass balance 

equation.

K 98.116(b) Only annual production by product 

from each EAF (No CEMS).

K 98.116(e)(4) All.

K 98.116(e)(5) All.

L 98.126(b)(1) Only data used in calculating the 

absolute errors and data used in 

calculating the relative errors.

L 98.126(b)(2) All.

L 98.126(b)(6) Only mass of each fluorinecontaining reactant fed into the 

process.

L 98.126(b)(7) Only mass of each fluorinecontaining product produced by the 

process.

L 98.126(b)(8)(i) Only mass of each fluorinecontaining product that is removed 

from the process and fed into the 

destruction device.

L 98.126(b)(8)(ii) Only mass of each fluorinecontaining by-product that is 

removed from the process and fed 

into the destruction device.

L 98.126(b)(8)(iii) Only mass of each fluorine-
Page 158 of 168

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)

containing reactant that is removed 

from the process and fed into the 

destruction device.

L 98.126(b)(8)(iv) Only mass of each fluorinecontaining by-product that is 

removed from the process and 

recaptured.

L 98.126(b)(8)(v) All.

L 98.126(b)(9)(i) All.

L 98.126(b)(9)(ii) All.

L 98.126(b)(9)(iii) All.

L 98.126(b)(10) All.

L 98.126(b)(11) All.

L 98.126(b)(12) All.

L 98.126(c)(1) Only quantity of the process 

activity used to estimate emissions.

L 98.126(c)(2) All.

L 98.126(d) Only estimate of missing data.

L 98.126(f)(1) All.

L 98.126(g)(1) All.

L 98.126(h)(2) All.

N 98.146(b)(2) Only annual quantity of carbonate 

based-raw material charged to each 

continuous glass melting furnace.

N 98.146(b)(4) All.

N 98.146(b)(6) All.

O 98.156(a)(2) All.

O 98.156(a)(7) All.

O 98.156(a)(8) All.
Page 159 of 168

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)

O 98.156(a)(9) All.

O 98.156(a)(10) All.

O 98.156(b)(1) All.

O 98.156(b)(2) All.

O 98.156(d)(1) All.

O 98.156(d)(2) All.

O 98.156(d)(3) All.

O 98.156(d)(4) All.

O 98.156(d)(5) All.

O 98.156(e)(1) All.

P 98.166(b)(2) All.

P 98.166(b)(5) All.

P 98.166(b)(6) All.

Q 98.176(b) Only annual quantity taconite 

pellets, coke, iron, and raw steel 

(No CEMS).

Q 98.176(e)(1) All.

Q 98.176(e)(3) All.

Q 98.176(e)(4) All.

Q 98.176(f)(1) All.

Q 98.176(f)(2) All.

Q 98.176(f)(3) All.

Q 98.176(f)(4) All.

Q 98.176(g) All.

R 98.186(b)(6) All.

R 98.186(b)(7) All.

S 98.196(b)(2) All.
Page 160 of 168

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)

S 98.196(b)(3) All.

S 98.196(b)(5) All.

S 98.196(b)(6) All.

S 98.196(b)(8) All.

S 98.196(b)(10) All.

S 98.196(b)(11) All.

S 98.196(b)(12) All.

U 98.216(b) All.

U 98.216(e)(1) All.

U 98.216(e)(2) All.

U 98.216(f)(1) All.

U 98.216(f)(2) All.

V 98.226(c) All.

V 98.226(d) All.

V 98.226(i) All.

V 98.226(j) All.

V 98.226(m)(1) All.

V 98.226(m)(3) All.

V 98.226(m)(4) All.

V 98.226(m)(5) All.

V 98.226(m)(6) All.

V 98.226(p) 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.
Page 161 of 168

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)

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.

W 98.236(c)(6)(i)(D) All.

W 98.236(c)(6)(i)(E) All.

W 98.236(c)(6)(i)(F) All.

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.

W 98.236(c)(8)(i)(K) All.
Page 162 of 168

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)

W 98.236(c)(8)(ii)(A) All.

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)(vii) 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.
Page 163 of 168

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)

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.

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.

X 98.246(a)(4) Only monthly volume values, monthly 

mass values, monthly carbon content 

values, molecular weights for 

gaseous feedstocks, molecular 

weights for gaseous products, and 

indication of whether the 

alternative method in §98.243(c)(4) 

was used.

X 98.246(b)(5)(iii) All.

X 98.246(b)(5)(iv) All.

Y 98.256(e)(6) Only molar volume conversion factor 

for each flare.

Y 98.256(e)(7) Only molar volume conversion factor 

for each flare.

Y 98.256(e)(7)(ii) All.

Y 98.256(e)(9) Only annual volume of flare gas 

combusted, annual average higher 

heating value of the flare gas, 

volume of gas flared, average
Page 164 of 168

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)

molecular weight, carbon content of 

the flare, and molar volume 

conversion factor if using Eq. Y–3.

Y 98.256(e)(10) Only fraction of carbon in the flare 

gas contributed by methane.

Y 98.256(f)(7) Only molar volume conversion factor.

Y 98.256(f)(10) Only coke burn-off factor, annual 

throughput of unit, and average 

carbon content of coke.

Y 98.256(f)(11) Only units of measure for the unitspecific CH4 emission factor, 

activity data for calculating 

emissions, and unit-specific 

emission factor for CH4.

Y 98.256(f)(12) Only unit-specific emission factor 

for N2O, units of measure for the 

unit-specific N2O emission factor, 

and activity data for calculating 

emissions.

Y 98.256(f)(13) Only average carbon content of coke.

Y 98.256(h)(4) All.

Y 98.256(h)(5) Only value of the correction, annual 

volume of recycled tail gas (if used 

to calculate recycling correction 

factor), and annual average mole 

fraction of carbon in the tail gas 

(if used to calculate recycling 

correction factor).

Y 98.256(i)(5) Only annual mass of green coke fed, 

carbon content of green coke fed, 

annual mass of marketable coke 

produced, carbon content of 

marketable coke produced, and annual 

mass of coke dust removed from the 

process.
Page 165 of 168

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)

Y 98.256(i)(7) Only the unit-specific CH4 emission 

factor, units of measure for unitspecific CH4 emission factor, and 

activity data for calculating 

emissions.

Y 98.256(i)(8) Only units of measure for the unitspecific factor, activity data used 

for calculating emissions, and sitespecific emissions factor.

Y 98.256(j)(2) All.

Y 98.256(j)(5) Only CO2 emission factor.

Y 98.256(j)(6) Only CH4 emission factor.

Y 98.256(j)(7) Only carbon emission factor.

Y 98.256(j)(8) Only CO2 emission factor and carbon 

emission factor.

Y 98.256(j)(9) Only CH4 emission factor.

Y 98.256(k)(3) Only dimensions of coke drum or 

vessel, typical gauge pressure of 

the coking drum, typical void 

fraction of coke drum or vessel, 

annual number of coke-cutting cycles 

of coke drum or vessel, and molar 

volume conversion factor for each 

coke drum or vessel.

Y 98.256(k)(4) Only height and diameter of the coke 

drums, cumulative number of vessel 

openings for all delayed coking 

drums, typical venting pressure, 

void fraction, mole fraction of 

methane in coking gas.

Y 98.256(l)(5) Only molar volume conversion factor.

Y 98.256(m)(3) Only total quantity of crude oil 

plus the quantity of intermediate 

products received from off-site, CH4

emission factor used, and molar 
Page 166 of 168

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)

volume conversion factor.

Y 98.256(n)(3) All (if used in Equation Y–21 to 

calculate emissions from equipment 

leaks).

Y 98.256(o)(2)(ii) All.

Y 98.256(o)(4)(ii) All.

Y 98.256(o)(4)(iii) All.

Y 98.256(o)(4)(iv) All.

Y 98.256(o)(4)(v) All.

Y 98.256(o)(4)(vi) Only tank-specific methane 

composition data and annual gas 

generation volume.

Y 98.256(p)(2) Only quantity of materials loaded 

that have an equilibrium vapor-phase 

concentration of CH4 of 0.5 volume 

percent or greater.

Z 98.266(f)(5) All.

Z 98.266(f)(6) All.

AA 98.276(b) All.

AA 98.276(c) Only annual mass of the spent liquor 

solids combusted.

AA 98.276(d) All.

AA 98.276(e) All.

AA 98.276(f) All.

AA 98.276(g) All.

AA 98.276(h) All.

AA 98.276(i) All.

BB 98.286(b)(1) All.

BB 98.286(b)(4) All.
Page 167 of 168

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)

BB 98.286(b)(6) All.

CC 98.296(b)(5) Only monthly consumption of trona or 

liquid alkaline feedstock (for 

facilities using Equation CC–1).

CC 98.296(b)(6) Only monthly production of soda ash 

for each manufacturing line(for 

facilities using Equation CC–2).

CC 98.296(b)(7) 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.

EE 98.316(b)(6) All.

EE 98.316(b)(9) All.

GG 98.336(b)(6) All.

GG 98.336(b)(7) All.

GG 98.336(b)(10) 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).

TT 98.466(c)(3)(i) All.

TT 98.466(c)(3)(ii) Only waste disposal quantity and 
Page 168 of 168

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)

production quantity.

TT 98.466(c)(3)(iii) All.