1

MEMORANDUM 

FROM: Rachel Schmeltz, U.S. EPA, Climate Change Division 

TO: Docket EPA-HQ-OAR-2012-0934 

DATE: March 1, 2013 

SUBJECT: Table of 2013 Revisions to the Greenhouse Gas Reporting Rule 

1.0 INTRODUCTION 

The 2009 final GHG reporting rule (2009 final rule) was signed by EPA Administrator 

Lisa Jackson on September 22, 2009 and published in the Federal Register on October 30, 2009 

(74 FR 56260, October 30, 2009). The 2009 final rule, which became effective on December 29, 

2009, included reporting of GHGs from various facilities and suppliers, consistent with the 2008 

Consolidated Appropriations Act. Subsequent notices were published in 2010 finalizing the 

requirements for subparts T, FF, II, and TT (75 FR 39736, July 12, 2010), subpart W (75 FR 

74458, November 20, 2010), subparts I, L, DD, QQ, and SS (75 FR 74774, December 1, 2010), 

and subparts RR and UU (75 FR 75060, December 1, 2010). These requirements are contained 

in 40 CFR part 98.The rule does not require control of GHGs, rather it only requires that sources 

above certain threshold levels monitor and report emissions and other related data. 

Since promulgation of the rule, the EPA has identified a number of technical issues that 

need to be corrected and specific portions of the Mandatory Greenhouse Gases Reporting Rule 

(hereafter referred to as “Part 98”) that need to be clarified. The EPA is proposing to amend 

specific provisions in the Mandatory Reporting of Greenhouse Gases Rule to better reflect 

industry practices and improvements in climate research, correct technical and editorial errors 

that have been identified since promulgation, and to clarify or update certain provisions that have 

been the subject of questions from reporting entities. 

The purpose of this memorandum is to provide a detailed list of each change proposed in 

this action. The table in section 3.0 contains a list of each change proposed, the rule language for 
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the current requirement, and the proposed language. A brief explanation of the reason for the 

change is included for those items that are not specifically addressed in the preamble for this 

proposal. These changes are minor clarifications of the requirements text to better reflect EPA’s 

intent, simple corrections to calculation terms or cross-references that do not revise the output of 

the calculations, harmonizing changes within a subpart (such as changes to terminology), simple 

editorial and minor error corrections, or removal of redundant text. In total, these changes do not 

represent a change in reporting burden. Also available in the docket for this action is a set of 

documents in redline strikeout format for each section of Part 98 for which EPA is proposing 

changes. 

2.0 SUMMARY OF CHANGES INCLUDED 

EPA is proposing changes for the subparts identified in the table below. Significant 

changes that are not detailed in this memorandum include changes to tables for several subparts. 

The amended tables are available in the redline document for the individual subpart and as 

attachments to this memorandum. Tables that have been changed include: Table A-1, A-6, C-1, 

C-2, AA-1, AA-2, HH-1, HH-2, new Table HH-4, MM-1 NN-1, NN-2, and TT-1. 

 

Subpart 

A- General Provision 

C- General Stationary Fuel Combustion Sources 

E - Adipic Acid Production 

G – Ammonia Manufacturing 

H – Cement production 

K –Ferroalloy Production 

L –Fluorinated Gas Production 

N – Glass Production 

O - HCFC-22 Production and HFC-23 Destruction 

P – Hydrogen Production 

Q - Iron & Steel Production 

S – Lime Manufacturing 

V- Nitric Acid Production 

X – Petrochemical Production 

Y – Petroleum Refineries 

Z - Phosphoric Acid Production 

AA - Pulp & Paper Manufacturing 

BB - Silicon Carbide Production 

DD - Electrical Transmission and Distribution Equipment Use 
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Subpart 

FF - Underground Coal Mines 

HH – Municipal Solid Waste Landfills 

II - Industrial Wastewater Treatment 

MM- Suppliers of Petroleum Products 

NN – Suppliers of Natural Gas and Natural Gas Liquids 

PP – Suppliers of Carbon Dioxide 

QQ - Importers and Exporters of Fluorinated Greenhouse Gases Contained in PreCharged Equipment or Closed Cell Foams 

RR - Geologic Sequestration of Carbon Dioxide 

SS - Electrical Equipment Manufacture or Refurbishment 

TT - Industrial Waste Landfills 

UU - Injection of Carbon Dioxide 

3.0 SUMMARY OF TECHNICAL CORRECTIONS AND OTHER AMENDMENTS 

The following table summarizes the amendments proposed for various subparts of Part 98 

which are being addressed by the proposed 2013 Revisions to the Greenhouse Gas Reporting 

Rule. 

 
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Subpart Requirement Current Rule Text Proposed Rule Text 

A 98.3(c)(1) 98.3(c)(1) Facility name or supplier name (as 

appropriate), and physical street address of the facility or supplier, including the city, State, and zip code. 

98.3(c)(1) Facility name or supplier name (as appropriate), and physical street address of the facility or supplier, including the city, State, and zicode. If the facility does not have a physical street address, then the facility must provide the latitude and longitude representing the location of facility operations in decimal degree format. This must be provided in a comma-delimited “latitude, longitudcoordinate pair reported in decimal degrees to at least four digits to the right of the decimal. 

A 98.3(c)(11) (None) (viii) The facility or supplier must refer to the 

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

A 98.3(c )(13) (None) (13) ORIS code for each power generation unit tha

has been assigned an ORIS code by the Energy Information Administration. 

A 98.3(h)(4) (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, at least two days prior to the expiration of the 45-day period, and the Administrator does not respond to the request by the end of such period, the extension request is deemed to be automatically granted for 30 more days. During the automatic 30-day extension, the Administrator will determine what extension, if any, beyond the automatic extension is reasonable and will provide any such additional extension. 

(4) Notwithstanding paragraphs (h)(1) and (h)(2) othis section, upon request by the owner or operatorthe Administrator may provide reasonable extensioof 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 request for extension of the 45-day period, by e-mato an address prescribed by the Administrator prior to the expiration of the 45-day period, the extensiorequest is deemed to be automatically granted for 3days. The Administrator may grant an additional extension beyond the automatic 30-day extension ithe 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 texpiration of the automatic 30-day extension, provided the request demonstrates that it is not practicable to submit a revised report or informatiounder paragraphs (h)(1) and (h)(2) with 75 days. T
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Subpart Requirement Current Rule Text Proposed Rule Text 

Administrator will approve the extension request ithe request demonstrates 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. 

A 98.3(j)(3)(ii) (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 request. 

(ii) Any subsequent extensions to the original requmust be submitted to the Administrator within 4 weeks of the owner or operator identifying the neeto extend the request, but in any event no later than weeks before the date for the planned process equipment or unit shutdown that was provided in toriginal or most recently approved request. 

A 98.3(k)(1) (None) (k) Revised Global Warming Potentials. 

(1) General. Starting with reporting year 2013, facilities and suppliers must use the revised GWPs Table A-1 of this subpart, Global Warming Potentials (revised 2013), for calculating CO2e emissions for determining applicability to this part and for calculating CO2e emissions in annual GHG reports. 

A 98.3(k)(2) (None) (2) Special provision for reporting year 2013. A 

facility or supplier that was not subject a subpart opart 98 for reporting year 2012, but becomes subjea subpart due to a change in the GWP for one or more compounds in Table A-1 of this subpart, Global Warming Potentials (revised 2013), is not required to submit an annual GHG for reporting ye2013. Such facilities or suppliers must start monitoring and collecting GHG data in compliance with this part starting on January 1, 2014, and subman annual greenhouse gas report for reporting year 2014 by March 31, 2015. 

A 98.3(l) (None) (l) Special provision for best available monitoring 
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Subpart Requirement Current Rule Text Proposed Rule Text 

methods in 2014. This paragraph 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 (revised 2013). 

A 98.3(l)(1) (None) (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 monitorinand QA/QC requirements of a relevant subpart. Thowner or operator must use the calculation methodologies and equations in the “Calculating GHG Emissions” sections of each relevant subpartbut may use the best available monitoring method any parameter for which it is not reasonably feasibto acquire, install, and operate a 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 providin paragraph (l)(2) of this section. Best available monitoring methods means any of the following methods: 

A 98.3(l)(1)(i)- (iv) (None) (i) Monitoring methods currently used by the facili

that do not meet the specifications of a relevant subpart. (ii) Supplier data. (iii) Engineering calculations. (iv) Other company records. 

A 98.3(l)(2) (None) (2) Requests for extension of the use of best 

available monitoring methods. The owner or operamay submit a request to the Administrator to use oor more best available monitoring methods beyond March 31, 2014. (i) Timing of request. The extension request must bsubmitted to EPA no later than January 31, 2014. 
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Subpart Requirement Current Rule Text Proposed Rule Text 

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

A 98.3(l)(2)(ii)(

A) 

(None) (A) A list of specific items of monitoring 

instrumentation for which the request is being madand the locations where each piece of monitoring instrumentation will be installed. 

A 98.3(l)(2)(ii)(

B) 

(None) (B) Identification of the specific rule requirements 

(by rule subpart, section, and paragraph numbers) which the instrumentation is needed. 

A 98.3(l)(2)(ii)(

C) 

(None) (C) A description of the reasons that the needed 

equipment could not be obtained and installed befoApril 1, 2014. 

A 98.3(l)(2)(ii)(

D) 

(None) (D) If the reason for the extension is that the 

equipment cannot be purchased and delivered by April 1, 2014, supporting documentation such as thdate the monitoring equipment was ordered, investigation of alternative suppliers and the dates which alternative vendors promised delivery, backorder notices or unexpected delays, descriptioof actions taken to expedite delivery, and the curreexpected date of delivery. 

A 98.3(l)(2)(ii)(

E) 

(None) (E) If the reason for the extension is that the 

equipment cannot be installed without a process unshutdown, include supporting documentation demonstrating that it is not practicable to isolate thequipment 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 tdate of the next planned shutdown during which thmonitoring equipment can be installed. If there has been a shutdown or if there is a planned process unshutdown between [THE DATE OF PUBLICATIOOF THE FINAL RULE IN THE FEDERAL REGISTER] and April 1, 2014, include a justification of why the equipment could not be obtained and installed during that shutdown. 

A 98.3(l)(2)(ii)(

F) 

(None) (F) A description of the specific actions the facility 

will take to obtain and install the equipment as soo
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Subpart Requirement Current Rule Text Proposed Rule Text 

as reasonably feasible and the expected date by which the equipment will be installed and operatin

A 98.3(l)(2)(iii) (None) (iii) Approval criteria. To obtain approval, the own

or operator must demonstrate to the Administratorsatisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by April 1, 2014. The use obest available methods under this subsection (l) winot be approved beyond December 31, 2014. 

A 98.6 Continuous bleed means a continuous flow of 

pneumatic supply gas to the process measurement 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 comparedwith the process set-point to adjust gas pressure in the valve actuator. 

Continuous bleed means a continuous flow of pneumatic supply natural gas to the process controdevice (e.g. level control, temperature control, pressure control) where the supply gas pressure is modulated by the process condition, and then flowto the valve controller where the signal is comparewith the process set-point to adjust gas pressure in the valve actuator. 

A 98.6 Degasification system means the entirety of the 

equipment that is used to drain gas from underground and collect it at a common point, such as a vacuum pumping station. This includes all degasification wells and gob gas vent holes at the underground coal mine. Degasification systems include surface pre-mining, horizontal pre-mining, and post-mining systems. 

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

A 98.6 Intermittent 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. These are snapacting or throttling devices that discharge the full volume of the actuator intermittently when control action is necessary, but does not bleed continuously. 

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 levepressure, delta-pressure and temperature. These are snap-acting or throttling devices that discharge all a portion of the full volume of the actuator intermittently when control action is necessary, budoes not bleed continuously. 

A 98.6 (None) Fluidized Bed Combustor (FBC) means a 

combustion technology (e.g., a fluidized bed boilerwhere the maximum steady-state temperature 
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Subpart Requirement Current Rule Text Proposed Rule Text 

reached within the combustor (excluding periods ostartup, shutdown, and malfunction) during the combustion of solid fuels (e.g., coal, tire derived fuel, wood and wood residuals, agricultural byproducts, coke, municipal solid waste, or mixturof such fuels) is less than or equal to 19,900 degreeF. 

A 98.6 Ventilation well or shaft means a well 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 hole or shaft means a vent hole or shafemployed at an underground coal mine to serve as the outlet or conduit to move air from the ventilatiosystem out of the mine. 

A 98.6 Ventilation system means a system that is used to 

control the concentration of methane and other gaseswithin 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. This includes all ventilation shafts and wells at the underground coal mine. 

Ventilation system means a system that is used to control the concentration of methane and other gaswithin mine working areas through mine ventilatiorather than a mine degasification system. A ventilation system consists of fans that move air through the mine workings to dilute methane concentrations. 

A 98.6 98.6 No definition ORIS Code means the unique identifier assigned to 

each power plant in the National Electric Energy Data System (NEEDS). The ORIS code is a 4 diginumber assigned by the Energy Information Administration (EIA) at US Department of Energy power plants owned by utilities. 

A Table A-1 Table A-1 See Appendix A for changes to Table A-1 A Table A-6 Table A-6 See Appendix A for changes to Table A-6 

C 98.33(b)(1) (None) (viii) May be used for the combustion of a fuel list

in Table C-1 if the fuel is combusted in a unit with maximum rated heat input capacity greater than 25mmBtu/hr (or, pursuant to §98.36(c)(3), in a group units served by a common supply pipe, having at least one unit with a maximum rated heat input capacity greater than 250 mmBtu/hr), provided thaboth of the following conditions apply: (A) The use of Tier 4 is not required. (B) The fuel provides less than 10 percent of the 
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Subpart Requirement Current Rule Text Proposed Rule Text 

annual heat input to the unit, or if §98.36(c)(3) applies, to the group of units served by a common supply pipe. (ix) May not be used for the combustion of waste coal (i.e., waste anthracite (culm) and waste bituminous (gob)). 

C 98.33(b)(3)(ii

)(A) 

(A) The use of Tier 1 or 2 is permitted, as described in paragraphs (b)(1)(iii), (b)(1)(v), and (b)(2)(ii) ofthis section. 

(A) The use of Tier 1 or 2 is permitted, as describein paragraphs (b)(1)(iii), (b)(1)(v), (b)(1)(viii), and (b)(2)(ii) of this section. 

C 98.33(e)(1)(ii

) 

(ii) The procedures in paragraph (e)(5) of this section. 

(ii) The procedures in paragraph (e)(4) of this section. 

C 98.33(e)(3)(iv

)(B) 

(B) Multiply the result from paragraph (e)(3)(iv)(A) of this section by the appropriate default factor to determine the annual biogenic CO2 emissions, in metric tons. For MSW, use a default factor of 0.6 and for tires, use a default factor of 0.20. 

(B) Multiply the result from paragraph (e)(3)(iv)(Aof this section by the appropriate default factor to determine the annual biogenic CO2 emissions, in metric tons. For MSW, use a default factor of 0.55 and for tires, use a default factor of 0.20. 

C

98.36(b)(3) 

(3) Maximum rated heat input capacity of the unit in mmBtu/hr for boilers and process heaters only and relevant units of measure for other combustion units. 

(3) Maximum rated heat input capacity of the unit mmBtu/hr. 

C 98.36(c)(3) (3) ...As a second example, in accordance with 

§98.33(b)(1)(v), Tier 1 may be used regardless of unit size when natural gas is transported through the common pipe, if the annual fuel consumption is obtained from gas billing records in units of therms. ... 

(3) ...As a second example, in accordance with §98.33(b)(1)(v), Tier 1 may be used regardless of unit size when natural gas is transported through thcommon pipe, if the annual fuel consumption is obtained from gas billing records in units of thermor mmBtu. ... 

C Table C-1 Table C-1 See Appendix A for changes to Table C-1 C Table C-2 Table C-2 See Appendix A for changes to Table C-2 

E 98.53(b)(3) (3) You must measure the adipic acid production rate 

during the test and calculate the production rate for the test period in metric tons per hour. 

(3) You must measure the adipic acid production rduring the test and calculate the production rate for the test period in tons per hour. 

E 98.53(d) (d) If any N2O abatement technology “N” is located 

after your test point, you must determine the destruction efficiency according to paragraphs (d)(1), (2), or (3) of this section. 

(d) If the adipic acid production unit exhausts to anN2O abatement technology “N”, you must determithe destruction efficiency according to paragraphs (d)(1), (d)(2), or (d)(3) of this section. 

E 98.53(e) (e) If any N2O abatement technology “N” is located 

after your test point, you must determine the annual 

(e) If the adipic acid production unit exhausts to anN2O abatement technology “N”, you must determi
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Subpart Requirement Current Rule Text Proposed Rule Text 

amount of adipic acid produced while N2Oabatement technology “N” is operating according to §98.54(f). Then you must calculate the abatement factor for N2O abatement technology “N” according 

to Equation E–2 of this section. 

the annual amount of adipic acid produced while N2O abatement technology “N” is operating according to §98.54(f). Then you must calculate thabatement factor for N2O abatement technology “N

according to Equation E–2 of this section. 

E 98.53(e)

Equation E-2 

E 98.53(g)(1) DF = Destruction efficiency of N2O abatement 

technology “N” (percent of N2O removed from vent 

stream). 

DF = Destruction efficiency of N2O abatement technology “N” (decimal fraction of N2O removed 

from vent stream). 

E 98.53(g)(1) AF = Abatement utilization factor of N2O abatement 

technology “N” (percent of time that the abatement technology is operating). 

AF = Abatement utilization factor of N2O abatemetechnology “N” (decimal fraction of time that the abatement technology is operating). 

E 98.53(g)(2) DF1 = Destruction efficiency of N2O abatement 

technology 1 (percent of N2O removed from vent 

stream). 

DF1 = Destruction efficiency of N2O abatement technology 1 (decimal fraction of N2O removed fro

vent stream). 

E 98.53(g)(2) AF1 = Abatement utilization factor of N2O abatement 

technology 1 (percent of time that abatement technology 1 is operating). 

AF1 = Abatement utilization factor of N2Oabatement technology 1 (decimal fraction of time that abatement technology 1 is operating). 

E 98.53(g)(2) DF2 = Destruction efficiency of N2O abatement 

technology 2 (percent of N2O removed from vent 

stream). 

DF2 = Destruction efficiency of N2O abatement technology 2 (decimal fraction of N2O removed fro

vent stream). 

E 98.53(g)(2) AF2 = Abatement utilization factor of N2O abatement 

technology 2 (percent of time that abatement technology 2 is operating). 

AF2 = Abatement utilization factor of N2Oabatement technology 2 (decimal fraction of time that abatement technology 2 is operating). 

E 98.53(g)(2) DFN = Destruction efficiency of N2O abatement 

technology N (percent of N2O removed from vent 

stream). 

DFN = Destruction efficiency of N2O abatement technology “N” (decimal fraction of N2O removed 

from vent stream). 

E 98.53(g)(2) AFN = Abatement utilization factor of N2O

abatement technology N (percent of time that abatement technology N is operating). 

AFN = Abatement utilization factor of N2Oabatement technology “N” (decimal fraction of timthat abatement technology N is operating). 

E 98.53(g)(3) DFN = Destruction efficiency of N2O abatement 

technology “N” (percent of N2O removed from vent 

stream). 

DFN = Destruction efficiency of N2O abatement technology “N” (decimal fraction of N2O removed 

from vent stream). 

E 98.53(g)(3) AFN = Abatement utilization factor of N2O

abatement technology “N” (percent of time that the 

AFN = Abatement utilization factor of N2Oabatement technology “N” (decimal fraction of tim
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Subpart Requirement Current Rule Text Proposed Rule Text 

abatement technology is operating). that the abatement technology is operating).

E 98.53(g)(3) FCN = Fraction control factor of N2O abatement 

technology “N” (percent of total emissions from unit “z” that are sent to abatement technology “N”). 

FCN = Fraction control factor of N2O abatement technology “N” (decimal fraction of total emissionfrom unit “z” that are sent to abatement technology “N”). 

E 98.54(e) (e) You must determine the monthly amount of 

adipic acid produced. You must also determine the monthly amount of adipic acid produced during which N2O abatement technology, located after the test point, is operating. These monthly amounts are determined according to the methods in paragraphs (c)(1) or (2) of this section. 

(e) You must determine the monthly amount of adipic acid produced. You must also determine the monthly amount of adipic acid produced during which N2O abatement technology is operating. Themonthly amounts are determined according to the methods in paragraphs (c)(1) or (c)(2) of this sectio

E 98.54(f) (f) You must determine the annual amount of adipic 

acid produced. You must also determine the annual amount of adipic acid produced during which N2O abatement technology located after the test point is operating. These are determined by summing the respective monthly adipic acid production quantities determined in paragraph (e) of this section. 

(f) You must determine the annual amount of adipiacid produced. You must also determine the annuaamount of adipic acid produced during which N2O abatement technology is operating. These are determined by summing the respective monthly adipic acid production quantities determined in paragraph (e) of this section. 

G 98.73(b)(4) (4) You must calculate the annual process CO2 

emissions from each ammonia processing unit k at your facility summing emissions, as applicable from Equation G–1, G–2, and G–3 of this section using Equation G–4. 

(4) You must calculate the annual process CO2 

emissions from each ammonia processing unit k at your facility according to Equation G-4 of this section: 

G 98.73(b)(4) 

Equation G-4 

(Eq. G-4) 

G 98.73(b)(5)

Equation G-5 (Eq. G-5)

G 98.73(b)(5) ECO2k = Annual CO2 emissions from each ammonia 

processing unit (metric tons). 

ECO2,k = Annual CO2 emissions from each ammonprocessing unit k (metric tons). 

G 98.73(b)(5) n = Total number of ammonia processing units. j = Total number of ammonia processing units. G 98.75(b) (b) For missing feedstock supply rates or waste (b) For missing feedstock supply rates used to 

ECO ,2 k = CO ,2 G,k + CO ,2 L,k + CO ,2 S,

∑

=

=

j

k

CO ECO k

1

2 ,2
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Subpart Requirement Current Rule Text Proposed Rule Text 

recycle stream used to determine monthly feedstock consumption or monthly waste recycle stream quantity, you must determine the best available estimate(s) of the parameter(s), based on all available process data. 

determine monthly feedstock consumption , you must determine the best available estimate(s) of thparameter(s), based on all available process data. 

G 98.76(a) (a) If a CEMS is used to measure CO2 emissions, 

then you must report the relevant information required under §98.36 for the Tier 4 Calculation Methodology and the following information in this paragraph (a): 

(a) If a CEMS is used to measure CO2 emissions, then you must report the relevant information required under §98.36 for the Tier 4 Calculation Methodology and the information in paragraphs (a)(1) and (a)(2) of this section: 

G 98.76(b) (b) If a CEMS is not used to measure emissions, then 

you must report the following information: 

(b) If a CEMS is not used to measure emissions, thyou must report all of the following information inthis paragraph (b): 

G 98.76(b)(13) (13) CO2 from the steam reforming of a hydrocarbon 

or the gasification of solid and liquid raw material at the ammonia manufacturing process unit used to produce urea and the method used to determine the CO2 consumed in urea production. 

(13) Annual CO2 emissions (metric tons) from the steam reforming of a hydrocarbon or the gasificatiof solid and liquid raw material at the ammonia manufacturing process unit used to produce urea anthe method used to determine the CO2 consumed in 

urea production. 

H 98.86(a)(2) (2) Monthly cement production from each kiln at the

facility. 

(2)Annual facility cement production. 

K 98.113(d)(1)

Equation K-3 

2000/2205 = Conversion factor to convert tons to metric tons. 

2/2205 = Conversion factor to convert kg CH4/ton 

product to metric tons CH4. 

K 98.116(e)(2) No current requirement (2) Annual process CH4 emissions (in metric tons) 

from each EAF used for the production of any ferroalloy listed in Table K–1 of this subpart. 
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Subpart Requirement Current Rule Text Proposed Rule Text 

L 98.126(j) 

Introductory paragraph 

(j) Special provisions for reporting years 2011 and 2012 only. For reporting years 2011 and 2012, the owner or operator of a facility must comply with paragraphs (j)(1), (j)(2), and (j)(3) of this section. 

(j) Special provisions for reporting years 2011, 201and 2013 only. For reporting years 2011, 2012, and 2013, the owner or operator of a facility must comply with paragraphs (j)(1), (j)(2), and (j)(3) of this section. 

L 98.126(j)(1) (1) Timing. The owner or operator of a facility is not 

required to report the data elements at §98.3(c)(4)(iii) and §98.126(a)(2), (a)(3), (a)(4), (a)(6), (b), (c), (d), (e), (f), (g), and (h) of this section until the later of March 31, 2014 or the date set forth for that data element at §98.3(c)(4)(vii) and Table A–7 of Subpart A of this part. 

(1) Timing. The owner or operator of a facility is nrequired to report the data elements at §98.3(c)(4)(iii) and §98.126(a)(2), (a)(3), (a)(4), (a)(6), (b), (c), (d), (e), (f), (g), and (h) of this sectiuntil the later of March 31, 2015 or the date set forfor that data element at §98.3(c)(4)(vii) and Table 7 of Subpart A of this part. 

L 98.126(j)(3)(i

) 

(i) If you choose to use a default GWP rather than your best estimate of the GWP for fluorinated GHGs whose GWPs are not listed in Table A–1 to this subpart, use a default GWP of 10,000 for fluorinated GHGs that are fully fluorinated GHGs and use a default GWP of 2000 for other fluorinated GHGs. 

(i) If you choose to use a default GWP rather than your best estimate of the GWP for fluorinated GHGwhose GWPs are not listed in Table A–1 of subparA of this part, use a default GWP of 10,000 for fluorinated GHGs that are fully fluorinated GHGs and use a default GWP of 2000 for other fluorinateGHGs. 

N 98.143

Introductory paragraph 

You must calculate and report the annual process CO2 emissions from each continuous glass melting furnace using the procedure in paragraphs (a) and (b) of this section. 

You must calculate and report the annual process CO2 emissions from each continuous glass melting furnace using the procedure in paragraphs (a) through (c) of this section. 

N 98.143(b) (b) For each continuous glass melting furnace that is 

not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO2 emissions from the glass melting 

furnace by using either the procedure in paragraph (b)(1) of this section or the procedure in paragraphs (b)(2) through (b)(7) of this section, except as specified in paragraph (c) of this section. 

(b) For each continuous glass melting furnace that not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO2 emissions from the glass melting furnace by using either the procedure in paragraph (b)(1) of this section or the procedure in paragraph (b)(2) of this section, except as specified in paragraph (c) of this section. 

N 98.143(b)(2)(

iv) 

MFi = Annual average mass fraction of carbonate- based mineral i in carbonate-based raw material i (percentage, expressed as a decimal). 

MFi = Annual average decimal mass fraction of carbonate-based mineral i in carbonate-based raw material i. 

N 98.143(b)(2)(

iv) 

Fi = Fraction of calcination achieved for carbonate- based raw material i, assumed to be equal to 1.0 (percentage, expressed as a decimal). 

Fi = Decimal fraction of calcination achieved for carbonate-based raw material i, assumed to be equto 1.0. 

N 98.144(b) (b) You must measure carbonate-based mineral mass 

fractions at least annually to verify the mass fraction 

(b) You must measure carbonate-based mineral mafractions at least annually to verify the mass fractio
15

Subpart Requirement Current Rule Text Proposed Rule Text 

data provided by the supplier of the raw material; such measurements shall be based on sampling and chemical analysis using ASTM D3682–01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes (incorporated by reference, see §98.7) or ASTM D6349–09 Standard Test Method for Determination of Major and Minor Elements in Coal, Coke, and Solid Residues from Combustion of Coal and Coke by Inductively Coupled Plasma—Atomic Emission Spectrometry (incorporated by reference, see §98.7). 

data provided by the supplier of the raw material; such measurements shall be based on sampling and chemical analysis using consensus standards that specify X-ray fluorescence. For measurements madin years prior to the emissions reporting year 2014you may also use ASTM D3682–01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes (incorporated by reference, s§98.7) or ASTM D6349–09 Standard Test Method for Determination of Major and Minor Elements in Coal, Coke, and Solid Residues from Combustion Coal and Coke by Inductively Coupled Plasma—Atomic Emission Spectrometry (incorporated by reference, see §98.7). 

N 98.146(b)(4) (4) Carbonate-based mineral mass fraction 

(percentage, expressed as a decimal) for each carbonate-based raw material charged to a continuous glass melting furnace. 

(4) Carbonate-based mineral decimal mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace. 

N 98.146(b)(6) (6) The fraction of calcination achieved for each 

carbonate-based raw material, if a value other than 1.0 is used to calculate process mass emissions of CO2. 

(6) The decimal fraction of calcination achieved foeach carbonate-based raw material, if a value other than 1.0 is used to calculate process mass emissionof CO2. 

N 98.146(b)(7) (7) Method used to determine fraction of calcination. (7) Method used to determine decimal fraction of 

calcination. 

N 98.147(b)(5) (5) The fraction of calcination achieved for each 

carbonate-based raw material (percentage, expressed as a decimal), if a value other than 1.0 is used to calculate process mass emissions of CO2. 

(5) The decimal fraction of calcination achieved foeach carbonate-based raw material, if a value other than 1.0 is used to calculate process mass emissionof CO2. 

O 98.153(c) (c) For HCFC–22 production facilities that do not 

use a thermal oxidizer or that have a thermal oxidizer that is not directly connected to the HCFC–22 production equipment, HFC–23 emissions shall be estimated using Equation O–4 of this section: 

(c) For HCFC–22 production facilities that do not use a destruction device or that have a destruction device that is not directly connected to the HCFC–production equipment, HFC–23 emissions shall be estimated using Equation O–4 of this section: 

O 98.153(d) (d) For HCFC–22 production facilities that use a 

thermal oxidizer connected to the HCFC–22 production equipment, HFC–23 emissions shall be estimated using Equation O–5 of this section:  (Eq. O-5) 

(d) For HCFC–22 production facilities that use a destruction device connected to the HCFC–22 production equipment, HFC–23 emissions shall be estimated using Equation O–5 of this section:  (Eq. O-5) 
16

Subpart Requirement Current Rule Text Proposed Rule Text 

Where:ED = Mass of HFC–23 emitted annually from thermal oxidizer (metric tons), calculated using Equation O–8 of this section. 

Where:ED = Mass of HFC–23 emitted annually from destruction device (metric tons), calculated using Equation O–8 of this section. 

O 98.154(j) (j) The number of sources of equipment type t with 

screening values less than 10,000 ppmv shall be the difference between the number of leak sources of equipment type t that could emit HFC-23 and the number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv as determined under paragraph (h) of this section. 

(j) The number of sources of equipment type t with screening values less than 10,000 ppmv shall be thdifference between the number of leak sources of equipment type t that could emit HFC-23 and the number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv as determined under paragraph (i) of this section. 

O 98.156(c) (c) Each HFC-23 destruction facility shall report the

concentration (mass fraction) of HFC-23 measured at the outlet of the destruction device during the facility's annual HFC-23 concentration measurements at the outlet of the device. 

(c) Each HFC-23 destruction facility shall report thconcentration (mass fraction) of HFC-23 measured the outlet of the destruction device during the facility's annual HFC-23 concentration measurements at the outlet of the device. If the concentration of HFC-23 is below the detection limof the measuring device, report the detection limit and that the concentration is below the detection limit. 

P 98.163(b) (b) Fuel and feedstock material balance approach. 

Calculate and report CO2 emissions as the sum of the annual emissions associated with each fuel and feedstock used for hydrogen production by following paragraphs (b)(1) through (b)(3) of this section. 

(b) Fuel and feedstock material balance approach. Calculate and report CO2 emissions as the sum of tannual emissions associated with each fuel and feedstock used for hydrogen production by followiparagraphs (b)(1) through (b)(3) of this section. Thcarbon content and molecular weight shall be obtained from the analyses conducted in accordancwith §98.164(b)(2), (b)(3), or (b)(4), as applicable, from the missing data procedures in §98.165. If the analyses are performed annually, then the annual value shall be used as the monthly average. If the analyses are performed more frequently than monthly, use the arithmetic average of values 
17

Subpart Requirement Current Rule Text Proposed Rule Text 

obtained during the month as the monthly average.

P 98.163(b)(1) Fdstkn = Volume of the gaseous fuel and feedstock 

used in month n (scf (at standard conditions of 68 °F and atmospheric pressure) of fuel and feedstock). CCn = Average carbon content of the gaseous fuel and feedstock, from the results of one or more analyses for month n (kg carbon per kg of fuel and feedstock). If measurements are taken more frequently than monthly, use the arithmetic average of measurement values within the month to calculate a monthly average. MWn = Average molecular weight of the gaseous fuel and feedstock from the results of one or more analyses for month n (kg/kg-mole). 

Fdstkn = Volume of the gaseous fuel or feedstock used in month n (scf (at standard conditions of 68 and atmospheric pressure) of fuel or feedstock). CCn = Average carbon content of the gaseous fuel and feedstock for month n (kg carbon per kg of fueor feedstock). MWn = Average molecular weight of the gaseous fuel or feedstock for month n (kg/kg-mole). 

P 98.163(b)(2) Fdstkn = Volume of the liquid fuel and feedstock 

used in month n (gallons of fuel and feedstock). CCn = Average carbon content of the liquid fuel and feedstock, from the results of one or more analyses for month n (kg carbon per gallon of fuel and feedstock). 

Fdstkn =Volume of the liquid fuel or feedstock usein month n (gallons of fuel or feedstock). CCn = Average carbon content of the liquid fuel or feedstock, for month n (kg carbon per gallon of fueor feedstock). 

P 98.163(b)(3) Fdstkn = Mass of solid fuel and feedstock used in 

month n (kg of fuel and feedstock). CCn = Average carbon content of the solid fuel and feedstock, from the results of one or more analyses for month n (kg carbon per kg of fuel and feedstock). 

Fdstkn = Mass of solid fuel or feedstock used in month n (kg of fuel or feedstock). CCn = Average carbon content of the solid fuel or feedstock, for month n (kg carbon per kg of fuel or feedstock). 

P 98.164(b)(3) (3) Determine the carbon content of fuel oil, naphtha, 

and other liquid fuels and feedstocks at least monthly, except annually for standard liquid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for liquid fuels delivered by bulk transport (e.g., by truck or rail). 

(3) Determine the carbon content of fuel oil, naphtand other liquid fuels and feedstocks at least monthly, except annually for standard liquid hydrocarbon fuels and feedstocks having consistencomposition, or upon delivery for liquid fuels and feedstocks delivered by bulk transport (e.g., by truor rail). 

P 98.164(b)(4) (4) Determine the carbon content of coal, coke, and 

other solid fuels and feedstocks at least monthly, except annually for standard solid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for solid fuels delivered by bulk transport (e.g., by truck or rail). 

(4) Determine the carbon content of coal, coke, and other solid fuels and feedstocks at least monthly, except annually for standard solid hydrocarbon fueand feedstocks having consistent composition, or upon delivery for solid fuels and feedstocks delivered by bulk transport (e.g., by truck or rail). 
18

Subpart Requirement Current Rule Text Proposed Rule Text 

P 98.164(b)(5) (5) You must use the following applicable methods 

to determine the carbon content for all fuels and feedstocks, and molecular weight of gaseous fuels and feedstocks. Alternatively, you may use the results of continuous chromatographic analysis of the fuel and feedstock, provided that the gas chromatograph (GC) is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the GC are documented in the written monitoring plan for the unit under §98.3(g)(5). 

(5) You must use the following applicable methodto determine the carbon content for all fuels and feedstocks, and molecular weight of gaseous fuels and feedstocks. Alternatively, you may use the results of chromatographic analysis of the fuel and feedstock, provided that the chromatograph is operated, maintained, and calibrated according to tmanufacturer's instructions; and the methods used operation, maintenance, and calibration of the chromatograph are documented in the written monitoring plan for the unit under §98.3(g)(5). 

P 98.164(c) (c) For units using the calculation methodologies 

described in this section, the records required under §98.3(g) must include both the company records and a detailed explanation of how company records are used to estimate the following: (1) Fuel and feedstock consumption, when solid fuel and feedstock is combusted and a CEMS is not used to measure GHG emissions. (2) Fossil fuel consumption, when, pursuant to §98.33(e), the owner or operator of a unit that uses CEMS to quantify CO2 emissions and that combusts both fossil and biogenic fuels separately reports the biogenic portion of the total annual CO2 emissions. (3) Sorbent usage, if the methodology in §98.33(d) is used to calculate CO2 emissions from sorbent. 

(c ) [Reserved] 

P 98.164(d) (d) The owner or operator must document the 

procedures used to ensure the accuracy of the estimates of fuel and feedstock usage and sorbent usage (as applicable) in paragraph (b) of this section, including, but not limited to, calibration of weighing equipment, fuel and feedstock flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided. 

(d) [Reserved] 
19

Subpart Requirement Current Rule Text Proposed Rule Text 

P 98.166(a)(2) - (a)(3) (2) Annual quantity of hydrogen produced (metric tons) for each process unit and for all units 

combined. (3) Annual quantity of ammonia produced (metric tons), if applicable, for each process unit and for all units combined. 

(2) Annual quantity of hydrogen produced (metric tons) for each process unit. (3) Annual quantity of ammonia produced (metric tons), if applicable for each process unit. 

P 98.167(c ) (None) (c) For units using the calculation methodologies 

described 98.163(b), the records required under §98.3(g) must include both the company records ana detailed explanation of how company records are used to estimate the following: (1) Fuel and feedstock consumption, when solid fuand feedstock is combusted and a CEMS is not useto measure GHG emissions. (2) Fossil fuel consumption, when, pursuant to §98.33(e), the owner or operator of a unit that uses CEMS to quantify CO2 emissions and that combusboth fossil and biogenic fuels separately reports thbiogenic portion of the total annual CO2 emissions(3) Sorbent usage, if the methodology in §98.33(d) used to calculate CO2 emissions from sorbent. 

P 98.167(d) (None) (d) The owner or operator must document the 

procedures used to ensure the accuracy of the estimates of fuel and feedstock usage and sorbent usage (as applicable) in 98.163(b), including, but nlimited to, calibration of weighing equipment, fuel and feedstock flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, anthe technical basis for these estimates must be provided. 

Q 98.170

Introductory paragraph 

98.170 Definition of the source category.The iron and steel production source category includes facilities with any of the following processes: taconite iron ore processing, integrated iron and steel manufacturing, cokemaking not colocated with an integrated iron and steel manufacturing process, and electric arc furnace (EAF) steelmaking not colocated with an integrated 

98.170 Definition of the source category.The iron and steel production source category includes facilities with any of the following processes: taconite iron ore processing, integrated iron and steel manufacturing, cokemaking not colocated with an integrated iron and steel manufacturing process, direct reduction furnaces ncollocated with an integrated iron and steel 
20

Subpart Requirement Current Rule Text Proposed Rule Text 

iron and steel manufacturing process. Integrated iron and steel manufacturing means the production of steel from iron ore or iron ore pellets. At a minimum,an integrated iron and steel manufacturing process has a basic oxygen furnace for refining molten iron into steel. Each cokemaking process and EAF process located at a facility with an integrated iron and steel manufacturing process is part of the integrated iron and steel manufacturing facility. 

manufacturing process, and electric arc furnace (EAF) steelmaking not colocated with an integrateiron and steel manufacturing process. Integrated irand steel manufacturing means the production of steel from iron ore or iron ore pellets. At a minimuan integrated iron and steel manufacturing process has a basic oxygen furnace for refining molten iron into steel. Each cokemaking process and EAF process located at a facility with an integrated iron and steel manufacturing process is part of the integrated iron and steel manufacturing facility. 

Q 98.173(b)(1)(

i) 

(Csf) = Carbon content of the solid fuel, from the fuel analysis (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95). (C0) = Carbon content of the greenball (taconite) pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Cp) = Carbon content of the fired pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). 

(Csf) = Carbon content of the solid fuel, from the fuanalysis (expressed as a decimal fraction). (C0) = Carbon content of the greenball (taconite) pellets, from the carbon analysis results (expressed as a decimal fraction). (Cp) = Carbon content of the fired pellets, from the carbon analysis results (expressed as a decimal fraction). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). 

Q 98.173(b)(1)(

i) 

(Fs) = Annual mass of the solid fuel combusted (metric tons). 

(Fs) = Annual mass of the solid fuel used (metric tons). 

Q 98.173(b)(1)(

i) 

(Fg) = Annual volume of the gaseous fuel combusted (scf). 

(Fg) = Annual volume of the gaseous fuel used (scf

Q 98.173(b)(1)(

i) 

(Fl) = Annual volume of the liquid fuel combusted (gallons). 

(Fl) = Annual volume of the liquid fuel used (gallons). 

Q 98.173(b)(1)(

ii), 

(CIron) = Carbon content of the molten iron, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CScrap) = Carbon content of the ferrous scrap, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CFlux) = Carbon content of the flux materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CCarbon) = Carbon content of the carbonaceous 

(CIron) = Carbon content of the molten iron, from thcarbon analysis results (expressed as a decimal fraction). (CScrap) = Carbon content of the ferrous scrap, from the carbon analysis results (expressed as a decimal fraction). (CFlux) = Carbon content of the flux materials, from the carbon analysis results (expressed as a decimal fraction). (CCarbon) = Carbon content of the carbonaceous 
21

Subpart Requirement Current Rule Text Proposed Rule Text 

materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CSteel) = Carbon content of the steel, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CSlag) = Carbon content of the slag, from the carbon analysis (percent by weight, expressed as a decimal fraction). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). 

materials, from the carbon analysis results (expressas a decimal fraction). (CSteel) = Carbon content of the steel, from the carbanalysis results (expressed as a decimal fraction). (CSlag) = Carbon content of the slag, from the carboanalysis (expressed as a decimal fraction). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). 

Q 98.173(b)(1)(

iii) 

(CCoal) = Carbon content of the coal, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CCoke) = Carbon content of the coke, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). 

(CCoal) = Carbon content of the coal, from the carboanalysis results (expressed as a decimal fraction). (CCoke) = Carbon content of the coke, from the carbon analysis results (expressed as a decimal fraction). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). 

Q 98.173(b)(1)(

iv) 

(CFeed) = Carbon content of the mixed sinter feed materials that form the bed entering the sintering machine, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CSinter) = Carbon content of the sinter pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). 

(CFeed) = Carbon content of the mixed sinter feed materials that form the bed entering the sintering machine, from the carbon analysis results (expressas a decimal fraction). (CSinter) = Carbon content of the sinter pellets, from the carbon analysis results (expressed as a decimal fraction). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). 

Q 98.173(b)(1)(

iv) 

(Fg) = Annual volume of the gaseous fuel combusted (scf). 

(Fg) = Annual volume of the gaseous fuel used (scf

Q 98.173(b)(1)(

v) 

(v) For EAFs, estimate CO2 emissions using Equation Q-5 of this section. CO2=44/12*[(Iron)*(CIron)+(Scrap)*(CScrap)+(Flux)*(Cf)+(Electrode)*(CElectrode)+(Carbon)*(Cc)-(Steel)*(CSteel)-(Slag)*(CSlag)-(R)*(CR) 

(v) For EAFs, estimate CO2 emissions using Equation Q-5 of this section. CO2=44/12*[(Iron)*(CIron)+(Scrap)*(CScrap)+(FluxCFlux)+(Electrode)*(CElectrode)+(Carbon)*(CCarbon)-

(Steel)*(CSteel)+(Fg)*(Cgf)*MW/MVC*0.001-(Slag)*(CSlag)-(R)*(CR)] 
22

Subpart Requirement Current Rule Text Proposed Rule Text 

Where:CO2 = Annual CO2 mass emissions from the EAF (metric tons). 44/12 = Ratio of molecular weights, CO2 to carbon. 

(Iron) = Annual mass of direct reduced iron (if any) charged to the furnace (metric tons). (CIron) = Carbon content of the direct reduced iron, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Scrap) = Annual mass of ferrous scrap charged to the furnace (metric tons). (CScrap) = Carbon content of the ferrous scrap, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Flux) = Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons). (CFlux) = Carbon content of the flux materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Electrode) = Annual mass of carbon electrode consumed (metric tons). (CElectrode) = Carbon content of the carbon electrode, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (CCarbon) = Carbon content of the carbonaceous materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Steel) = Annual mass of molten raw steel produced by the furnace (metric tons). (CSteel) = Carbon content of the steel, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (Slag) = Annual mass of slag produced by the furnace (metric tons). 

Where: CO2 = Annual CO2 mass emissions from the EAF (metric tons). 44/12 = Ratio of molecular weights, CO2 to carbon

(Iron) = Annual mass of direct reduced iron (if anycharged to the furnace (metric tons). (CIron) = Carbon content of the direct reduced iron, 

from the carbon analysis results (expressed as a decimal fraction). (Scrap) = Annual mass of ferrous scrap charged to the furnace (metric tons). (CScrap) = Carbon content of the ferrous scrap, from the carbon analysis results (expressed as a decimal fraction). (Flux) = Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metritons). (CFlux) = Carbon content of the flux materials, from the carbon analysis results (expressed as a decimal fraction). (Electrode) = Annual mass of carbon electrode consumed (metric tons). (CElectrode) = Carbon content of the carbon electrode

from the carbon analysis results (expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous material(e.g., coal, coke) charged to the furnace (metric tons). (CCarbon) = Carbon content of the carbonaceous materials, from the carbon analysis results (expressas a decimal fraction). (Steel) = Annual mass of molten raw steel produceby the furnace (metric tons). (CSteel) = Carbon content of the steel, from the carbanalysis results (expressed as a decimal fraction). (Fg) = Annual volume of the gaseous fuel used (scf 60 degrees F and one atmosphere). 
23

Subpart Requirement Current Rule Text Proposed Rule Text 

(CSlag) = Carbon content of the slag, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). 

(Cgf) = Average carbon content of the gaseous fuelfrom the fuel analysis results (kg C per kg of fuel). (MW) = Molecular weight of the gaseous fuel (kg/kg-mole). (MVC) = Molar volume conversion factor (836.6 sper kg-mole at standard conditions of 60 degrees F and one atmosphere). (0.001) = Conversion factor from kg to metric tons(Slag) = Annual mass of slag produced by the furnace (metric tons). (CSlag) = Carbon content of the slag, from the carboanalysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). 

Q 98.173(b)(1)(

vi) 

(vi) For decarburization vessels, estimate CO2emissions using Equation Q-6 of this section. CO2=44/12*(Steel)*[(CSteelin)-(CSteelout)]-(R)*(CR) Where: CO2 = Annual CO2 mass emissions from the decarburization vessel (metric tons). 44/12 = Ratio of molecular weights, CO2 to carbon. 

(Steel) = Annual mass of molten steel charged to the vessel (metric tons). (CSteelin) = Carbon content of the molten steel before decarburization, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(CSteelout) = Carbon content of the molten steel after decarburization, from the carbon analysis results (percent by weight, expressed as a decimal fraction).(R) = Annual mass of air pollution control residue collected (metric tons). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). 

(vi) For decarburization vessels, estimate CO2emissions using Equation Q-6 of this section. CO2=44/12*{(Steel)*[(CSteelin)-(CSteelout)]-(R)*(CR)

Where: CO2 = Annual CO2 mass emissions from the decarburization vessel (metric tons). 44/12 = Ratio of molecular weights, CO2 to carbon

(Steel) = Annual mass of molten steel charged to thvessel (metric tons). (CSteelin) = Carbon content of the molten steel befordecarburization, from the carbon analysis results (expressed as a decimal fraction). (CSteelout) = Carbon content of the molten steel after decarburization, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). 
24

Subpart Requirement Current Rule Text Proposed Rule Text 

Q 98.173(b)(1)(

vii) 

(Fg) = Annual volume of the gaseous fuel combusted (scf). 

(Fg) = Annual volume of the gaseous fuel used (scf

Q 98.173(b)(1)(

vii) 

(COre) = Carbon content of the iron ore or iron ore pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CCarbon) = Carbon content of the carbonaceous materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (COther) = Average carbon content of the other materials charged to the furnace, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CIron) = Carbon content of the iron, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CNM) = Carbon content of the non-metallic materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction). 

(COre) = Carbon content of the iron ore or iron ore pellets, from the carbon analysis results (expressed as a decimal fraction). (CCarbon) = Carbon content of the carbonaceous materials, from the carbon analysis results (expressas a decimal fraction). (COther) = Average carbon content of the other materials charged to the furnace, from the carbon analysis results (expressed as a decimal fraction). (CIron) = Carbon content of the iron, from the carboanalysis results (expressed as a decimal fraction). (CNM) = Carbon content of the non-metallic materials, from the carbon analysis results (expressas a decimal fraction). (CR) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). 

Q 98.173(c ) (c) You must determine emissions of CO2 from the 

coke pushing process in mtCO2e by multiplying the 

metric tons of coal charged to the coke ovens during the reporting period by 0.008. 

(c) You must determine emissions of CO2 from the coke pushing process in mtCO2e by multiplying thmetric tons of coal charged to the by-product recovery and non-recovery coke ovens during the reporting period by 0.008. 

Q 98.173(d) (d)If GHG emissions from a taconite indurating 

furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, decarburization vessel, or direct reduction furnace are vented through the same stack as any combustion unit or process equipment that reports CO2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according 

(d)If GHG emissions from a taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, decarburization vessel, or direct reduction furnace are vented throua stack equipped with a CEMS that complies with the Tier 4 methodology in subpart C of this part, or through the same stack as any combustion unit or process equipment that reports CO2 emissions usin

a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process 
25

Subpart Requirement Current Rule Text Proposed Rule Text 

to the Tier 4 Calculation Methodology in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). 

emissions. The owner or operator shall report undethis subpart the combined stack emissions accordinto the Tier 4 Calculation Methodology in §98.33(a)(4) and comply with all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). 

Q 98.174(b)(1) (1) Except as provided in paragraph (b)(4) of this 

section, determine the mass of each process input and output other than fuels using the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, weighed purchased quantities in shipments or containers, combination of bulk density and volume measurements, etc.), record the totals for each process input and output for each calendar month, and sum the monthly mass to determine the annual mass for each process input and output. Determine the mass rate of fuels using the procedures for combustion units in §98.34. 

(1) Except as provided in paragraph (b)(4) of this section, determine the mass of each process input and output other than fuels using the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, weighed purchased quantities in shipments or containers, combination of bulk densand volume measurements, etc.), record the totals feach process input and output for each calendar month, and sum the monthly mass to determine the annual mass for each process input and output. Determine the mass rate of fuels using the procedures for combustion units in §98.34. No determination of the mass of steel output from decarburization vessels is required. 

Q 98.174(c )(2) (2)For the furnace exhaust from basic oxygen 

furnaces, EAFs, decarburization vessels, and direct reduction furnaces, sample the furnace exhaust for at least three complete production cycles that start when the furnace is being charged and end after steel or iron and slag have been tapped. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, develop an emission factor for theproduction of both types of steel. 

(2)(i) For the exhaust from basic oxygen furnaces, EAFs, decarburization vessels, and direct reduction furnaces, sample the furnace exhaust for at least three complete production cycles that start when thfurnace is being charged and end after steel or iron and slag have been tapped. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, develop an emission factor for the production of both types of steel. (ii) For the exhaust from continuously charged EAFs, sample the exhaust for a period spanning at least three three hours. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, develop an emission factor for the production of both types of steel. 

Q 98.175(a) (a) For each missing data for the carbon content of 

inputs and outputs for facilities that estimate emissions using the carbon mass balance procedure 

(a) Except as provided in §98.174(b)(4), 100 percedata availability is required for the carbon content inputs and outputs for facilities that estimate 
26

Subpart Requirement Current Rule Text Proposed Rule Text 

in §98.173(b)(1) or for facilities that estimate emissions using the site-specific emission factor procedure in §98.173(b)(2); 100 percent data availability is required. You must repeat the test for average carbon contents of inputs and outputs according to the procedures in §98.174(b)(2). Similarly, you must repeat the test to determine the site-specific emission factor if data on the CO2

emission rate, process production rate or process feed rate are missing. 

emissions using the carbon mass balance procedurin §98.173(b)(1) or facilities that estimate emissionusing the site-specific emission factor procedure in §98.173(b)(2). 

Q 98.176(e) (e) If you use the carbon mass balance method in 

§98.173(b)(1) to determine CO2 emissions, you must report the following information for each process: 

(e) If you use the carbon mass balance method in §98.173(b)(1) to determine CO2 emissions, you must, except as provided in §98.174(b)(4), report tfollowing information for each process: 

Q 98.177(b) (b) When the carbon mass balance method is used to 

estimate emissions for a process, the monthly mass of each process input and output that are used to determine the annual mass. 

(b) When the carbon mass balance method is used estimate emissions for a process, the monthly mass of each process input and output that are used to determine the annual mass, except that no determination of the mass of steel output from decarburization vessels is required. 

S 98.190 (a) (a) Lime manufacturing plants (LMPs) engage in the 

manufacture of a lime product (e.g., calcium oxide, high-calcium quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, dolomitic hydrate, or other lime products) by calcination of limestone, dolomite, shells or other calcareous substances as defined in 40 CFR 63.7081(a)(1). 

(a) Lime manufacturing plants (LMPs) engage in tmanufacture of a lime product by calcination of limestone, dolomite, shells or other calcareous substances as defined in 40 CFR 63.7081(a)(1). 

S 98.193(a) (a) If all lime kilns meet the conditions specified in 

§98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO2 emissions by operating and 

maintaining a CEMS to measure CO2 emissions 

according to the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). 

(a) If all lime kilns meet the conditions specified in §98.33(b)(4)(ii) or (b)(4)(iii), you must calculate areport under this subpart the combined process and combustion CO2 emissions from all lime kilns by operating and maintaining a CEMS to measure CO

emissions according to the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). 

S 98.193(b)(1) (1) Calculate and report under this subpart the 

combined process and combustion CO2 emissions by 

(1) Calculate and report under this subpart the combined process and combustion CO2 emissions 
27

Subpart Requirement Current Rule Text Proposed Rule Text 

operating and maintaining a CEMS to measure CO2emissions from all lime kilns according to the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). 

from all lime kilns by operating and maintaining a CEMS to measure CO2 emissions from all lime kilaccording to the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). 

S 98.193(b)(2) (2) Calculate and report process and combustion CO2

emissions separately using the procedures specified in paragraphs (b)(2)(i) through (b)(2)(v) of this section. 

(2) Calculate and report process and combustion Cemissions from all lime kilns separately using the procedures specified in paragraphs (b)(2)(i) throug(b)(2)(v) of this section. 

S 98.193(b)(2)(

ii) 

(ii) You must calculate a monthly emission factor for each type of calcined byproduct/waste sold (including lime kiln dust) using Equation S–2 of this section: 

(ii) You must calculate a monthly emission factor feach type of calcined byproduct or waste sold (including lime kiln dust) using Equation S–2 of thsection: 

S 98.193(b)(2)(

ii) 

EFLKD,I,N= Emission factor for calcined lime byproduct/waste type i sold, for month n (metric tons CO2/ton lime product. 

EFLKD,I,N= Emission factor for calcined lime byproduct or waste type i sold, for month n (metric tons CO2/ton lime product. 

S 98.193(b)(2)(

ii) 

CaOLKD,i,n= Calcium oxide content for calcined lime byproduct/ waste type i sold, for month n (metric tons CaO / metric ton lime). 

CaOLKD,i,n= Calcium oxide content for calcined limbyproduct or waste type i sold, for month n (metric tons CaO / metric ton lime). 

S 98.193(b)(2)(

ii) 

MgOLKD,i,n= Magnesium oxide content for calcined lime byproduct/waste type i sold, for month n (metric tons MgO / metric ton lime). 

MgOLKD,i,n= Magnesium oxide content for calcined lime byproduct or waste type i sold, for month n (metric tons MgO / metric ton lime). 

S 98.193(b)(2)(

iii) 

(iii) You must calculate the annual CO2 emissions from each type of calcined byproduct/waste that is not sold (including lime kiln dust and scrubber sludge) using Equation S–3 of this section: 

(iii) You must calculate the annual CO2 emissions from each type of calcined byproduct or waste that not sold (including lime kiln dust and scrubber sludge) using Equation S–3 of this section: 

S 98.193(b)(2)(

iii) 

Ewaste,i= Annual CO2 emissions for calcined lime byproduct/waste type i that is not sold (metric tons CO2) 

Ewaste,i= Annual CO2 emissions for calcined lime byproduct or waste type i that is not sold (metric toCO2) 

S 98.193(b)(2)(

iii) 

CaOwaste,i= Calcium oxide content for calcined lime byproduct/ waste type i that is not sold (metric tons CaO / metric ton lime). 

CaOwaste,i= Calcium oxide content for calcined limbyproduct or waste type i that is not sold (metric toCaO / metric ton lime). 

S 98.193(b)(2)(

iii) 

MgOWaste,i= Magnesium oxide content for calcined lime byproduct/ waste type i that is not sold (metric tons MgO / metric ton lime). 

MgOWaste,i= Magnesium oxide content for calcined lime byproduct or waste type i that is not sold (metric tons MgO / metric ton lime). 

S 98.193(b)(2)(

iii) 

MWaste,i= Annual weight or mass of calcined byproducts/wastes for lime type i that is not sold 

MWaste,i= Annual weight or mass of calcined byproducts or wastes for lime type i that is not sold 
28

Subpart Requirement Current Rule Text Proposed Rule Text 

(tons). (tons).

S 98.193b(2)(iv

) 

(iv) You must calculate annual CO2 process emissions for all kilns using Equation S–4 of this section: 

(iv) You must calculate annual CO2 process emissions for all lime kilns using Equation S–4 of this section: 

S 98.193b(2)(iv

) 

ECO2 = Annual CO2 process emissions from lime production from all kilns (metric tons/year). 

ECO2 = Annual CO2 process emissions from lime production from all lime kilns (metric tons/year). 

S 98.193b(2)(iv

) 

EFLKD,i,n = Emission factor of calcined byproducts/wastes sold for lime type i in calendar month n, (metric tons CO2/ton byproduct/waste) 

from Equation S–2 of this section. 

EFLKD,i,n = Emission factor of calcined byproducts wastes sold for lime type i in calendar month n, (metric tons CO2/ton byproduct or waste) from Equation S–2 of this section. 

S 98.193b(2)(iv

) MLKD,i,n = Monthly weight or mass of calcined 

byproducts/waste sold (such as lime kiln dust, LKD) for lime type i in calendar month n (tons). 

MLKD,i,n = Monthly weight or mass of calcined byproducts or waste sold (such as lime kiln dust, LKD) for lime type i in calendar month n (tons). 

S 98.193b(2)(iv

) 

Ewaste,i = Annual CO2 emissions for calcined lime byproduct/waste type i that is not sold (metric tons CO2) from Equation S–3 of this section. 

Ewaste,i = Annual CO2 emissions for calcined lime byproduct or waste type i that is not sold (metric toCO2) from Equation S–3 of this section. 

S 98.193b(2)(iv

) 

b = Number of calcined byproducts/wastes that are sold. 

b = Number of calcined byproducts or wastes that sold. 

S 98.193b(2)(iv

) 

z = Number of calcined byproducts/wastes that are not sold. 

z = Number of calcined byproducts or wastes that not sold. 

S 98.194(a) (a) You must determine the total quantity of each 

type of lime product that is produced and each calcined byproduct/waste (such as lime kiln dust) that is sold. The quantities of each should be directly measured monthly with the same plant instruments used for accounting purposes, including but not limited to, calibrated weigh feeders, rail or truck scales, and barge measurements. The direct measurements of each lime product shall be reconciled annually with the difference in the beginning of and end of year inventories for these products, when measurements represent lime sold. 

(a) You must determine the total quantity of each type of lime product that is produced and each calcined byproduct or waste (such as lime kiln dusthat is sold. The quantities of each should be directmeasured monthly with the same plant instruments used for accounting purposes, including but not limited to, calibrated weigh feeders, rail or truck scales, and barge measurements. The direct measurements of each lime product shall be reconciled annually with the difference in the beginning of and end of year inventories for these products, when measurements represent lime sold. 

S 98.194(b) (b) You must determine the annual quantity of each 

calcined byproduct/waste generated that is not sold by either direct measurement using the same 

(b) You must determine the annual quantity of each calcined byproduct or waste generated that is not sold by either direct measurement using the same 
29

Subpart Requirement Current Rule Text Proposed Rule Text 

instruments identified in paragraph (a) of this section or by using a calcined byproduct/waste generation rate. 

instruments identified in paragraph (a) of this sectior by using a calcined byproduct or waste generatirate. 

S 98.194(c) (c) You must determine the chemical composition 

(percent total CaO and percent total MgO) of each type of lime product that is produced and each type of calcined byproduct/waste sold according to paragraph (c)(1) or (2) of this section. You must determine the chemical composition of each type of lime product that is produced and each type of calcined byproduct/waste sold on a monthly basis. You must determine the chemical composition for each type of calcined byproduct/waste that is not sold on an annual basis. 

(c) You must determine the chemical composition (percent total CaO and percent total MgO) of each type of lime product that is produced and each type of calcined byproduct or waste sold according to paragraph (c)(1) or (2) of this section. You must determine the chemical composition of each type olime product that is produced and each type of calcined byproduct or waste sold on a monthly basYou must determine the chemical composition for each type of calcined byproduct or waste that is nosold on an annual basis. 

S 98.195(a) (a) For each missing value of the quantity of lime 

produced (by lime type), and quantity of calcined byproduct/waste produced and sold, the substitute data value shall be the best available estimate based on all available process data or data used for accounting purposes. 

(a) For each missing value of the quantity of lime produced (by lime type), and quantity of calcined byproduct or waste produced and sold, the substitudata value shall be the best available estimate baseon all available process data or data used for accounting purposes. 

S 98.196(a)(1) (1) Method used to determine the quantity of lime 

that is produced and sold. 

(1) Method used to determine the quantity of lime that is produced and quantity of lime that is sold. 

S 98.196(a)(2) (2) Method used to determine the quantity of 

calcined lime byproduct/waste sold. 

(2) Method used to determine the quantity of calcined lime byproduct or waste sold. 

S 98.196(a)(4) (4) Beginning and end of year inventories for 

calcined lime byproducts/wastes sold, by type. 

(4) Beginning and end of year inventories for calcined lime byproducts or wastes sold, by type. 

S 98.196(a)(5) (5) Annual amount of calcined lime byproduct/waste 

sold, by type (tons). 

(5) Annual amount of calcined lime byproduct or waste sold, by type (tons). 

S 98.196(a)(7) (7) Annual amount of calcined lime byproduct/waste 

that is not sold, by type (tons). 

(7) Annual amount of calcined lime byproduct or waste that is not sold, by type (tons). 

S 98.196(b)(1) (1) Annual CO2 process emissions from all kilns 

combined (metric tons). 

(1) Annual CO2 process emissions from all lime kilns combined (metric tons). 

S 98.196(b)(2) (2) Monthly emission factors for each lime type 

produced. 

(2) Monthly emission factors (metric ton CO2/ton lime product) for each lime product type produced

S 98.196(b)(3) (3) Monthly emission factors for each calcined 

byproduct/waste by lime type that is sold. 

(3) Monthly emission factors for each calcined byproduct or waste by lime type that is sold. 

S 98.196(b)(4) (4) Standard method used (ASTM or NLA testing 

method) to determine chemical compositions of each 

(4) Standard method used (ASTM or NLA testing method) to determine chemical compositions of ea
30

Subpart Requirement Current Rule Text Proposed Rule Text 

lime type produced and each calcined lime byproduct/waste type. 

lime type produced and each calcined lime byprodor waste type. 

S 98.196(b)(5) (5) Monthly results of chemical composition analysis 

of each type of lime product produced and calcined byproduct/waste sold. 

(5) Monthly results of chemical composition analyof each type of lime product produced and calcined byproduct or waste sold. 

S 98.196(b)(6) (6) Annual results of chemical composition analysis 

of each type of lime byproduct/waste that is not sold. 

(6) Annual results of chemical composition analysiof each type of lime byproduct or waste that is not sold. 

S 98.196(b)(9) (9) Method used to determine the quantity of 

calcined lime byproduct/waste sold. 

(9) Method used to determine the quantity of calcined lime byproduct or waste sold. 

S 98.196(b)(10) (10) Monthly amount of calcined lime 

byproduct/waste sold, by type (tons). 

(10) Monthly amount of calcined lime byproduct owaste sold, by type (tons). 

S 98.196(b)(11) (11) Annual amount of calcined lime 

byproduct/waste that is not sold, by type (tons). 

(11) Annual amount of calcined lime byproduct or waste that is not sold, by type (tons). 

S 98.196(b)(14) (14) Beginning and end of year inventories for 

calcined lime byproducts/wastes sold. 

(14) Beginning and end of year inventories for calcined lime byproducts or wastes sold. 

V 98.222(a) (a) You must report N2O process emissions from 

each nitric acid production train as required by this subpart. 

(a) You must report N2O process emissions from each nitric acid train as required by this subpart. 

V 98.223(b) (b) You must conduct an annual performance test for 

each nitric acid train according to paragraphs (b)(1) through (3) of this section. 

(b) You must conduct an annual performance test feach nitric acid train according to paragraphs (b)(1through (b)(3) of this section. 

V 98.223(b)(1) (1) You must conduct the performance test at the 

absorber tail gas vent, referred to as the test point, for each nitric acid train according to §98.224(b) through (f). If multiple nitric acid production units exhaust to a common abatement technology and/or emission point, you must sample each process in the ducts before the emissions are combined, sample each process when only one process is operating, or sample the combined emissions when multiple processes are operating and base the site-specific emission factor on the combined production rate of the multiple nitric acid production units. 

(1) You must conduct the performance test at the absorber tail gas vent, referred to as the test point, each nitric acid train according to §98.224(b) through (f). If multiple nitric acid trains exhaust to common abatement technology and/or emission point, you must sample each process in the ducts before the emissions are combined, sample each process when only one process is operating, or sample the combined emissions when multiple processes are operating and base the site-specific emission factor on the combined production rate of the multiple nitric acid trains. 

V 98.223(b)(3) (3) You must measure the production rate during the 

performance test and calculate the production rate for the test period in metric tons (100 percent acid basis) 

(3) You must measure the production rate during thperformance test and calculate the production rate the test period in tons (100 percent acid basis) per 
31

Subpart Requirement Current Rule Text Proposed Rule Text 

per hour. hour.

V 98.223(d) (d) If nitric acid train “t” exhausts to any N2O

abatement technology “N” after the test point, you must determine the destruction efficiency for each N2O abatement technology “N” according to paragraphs (d)(1), (d)(2), or (d)(3) of this section. 

(d) If nitric acid train “t” exhausts to any N2Oabatement technology “N”, you must determine thdestruction efficiency for each N2O abatement 

technology “N” according to paragraphs (d)(1), (d)(2), or (d)(3) of this section. 

V 98.223(e) (e) If nitric acid train “t” exhausts to any N2O

abatement technology “N” after the test point, you must determine the annual amount of nitric acid produced on train “t” while N2O abatement technology “N” is operating according to §98.224(f). Then you must calculate the abatement utilization factor for each N2O abatement technology “N” for each nitric acid train “t” according to Equation V–2 of this section. 

(e) If nitric acid train “t” exhausts to any N2Oabatement technology “N”, you must determine thannual amount of nitric acid produced on nitric acitrain “t” while N2O abatement technology “N” is operating according to §98.224(f). Then you must calculate the abatement utilization factor for each N2O abatement technology “N” for each nitric acid train “t” according to Equation V–2 of this section

V 98.223(e) Pa,t,N Pt,N V 98.223(g)(1) EN2Ot = Annual N2O mass emissions from nitric 

acid production unit “t” according to this Equation V–3a (metric tons) 

EN2Ot = Annual N2O mass emissions from nitric acid train “t” according to this Equation V–3a (metric tons). 

V 98.223(g)(1) Pt = Annual nitric acid production from the train “t” 

(ton acid produced, 100 percent acid basis). 

Pt = Annual nitric acid production from nitric acid train “t” (ton acid produced, 100 percent acid basis

V 98.223(g)(1) DF = Destruction efficiency of N2O abatement 

technology N that is used on nitric acid train “t” (percent of N2O removed from vent stream). 

DF = Destruction efficiency of N2O abatement technology N that is used on nitric acid train “t” (decimal fraction of N2O removed from vent stream

V 98.223(g)(1) AF = Abatement utilization factor of N2O abatement 

technology “N” for nitric acid train “t” (percent of time that the abatement technology is operating). 

AF = Abatement utilization factor of N2O abatemetechnology “N” for nitric acid train “t” (decimal fraction of annual production during which abatement technology is operating). 

V 98.223(g)(2) (2) If multiple N2O abatement technologies are 

located in series after your test point, you must use the emissions factor (determined in Equation V–1 of this section), the destruction efficiency (determined in paragraph (d) of this section), the annual nitric acid production (determined in paragraph (f) of this section), and the abatement utilization factor (determined in paragraph (e) of this section), according to Equation V–3b of this section: 

(2) If multiple N2O abatement technologies are located in series after your test point, you must use the emissions factor (determined in Equation V–1 this section), the destruction efficiency (determined in paragraph (d) of this section), the annual nitric acid production (determined in paragraph (i) of thisection), and the abatement utilization factor (determined in paragraph (e) of this section), according to Equation V–3b of this section: 

V 98.223(g)(2) EN2Ot = Annual N2O mass emissions from nitric acid EN2Ot = Annual N2O mass emissions from nitric a
32

Subpart Requirement Current Rule Text Proposed Rule Text 

production unit “t” according to this Equation V–3b (metric tons). 

train “t” according to this Equation V–3b (metric tons). 

V 98.223(g)(2) EFN2O,t = N2O emissions factor for unit “t” (lb 

N2O/ton nitric acid produced). 

EFN2O,t = N2O emissions factor for nitric acid train “t” (lb N2O/ton nitric acid produced). 

V 98.223(g)(2) Pt = Annual nitric acid produced from unit “t” (ton 

acid produced, 100 percent acid basis). 

Pt = Annual nitric acid produced from nitric acid train “t” (ton acid produced, 100 percent acid basis

V 98.223(g)(2) DF1 = Destruction efficiency of N2O abatement 

technology 1 (percent of N2O removed from vent stream). 

DF1 = Destruction efficiency of N2O abatement technology 1 (decimal fraction of N2O removed frovent stream). 

V 98.223(g)(2) AF1 = Abatement utilization factor of N2O abatement 

technology 1 (percent of time that abatement technology 1 is operating). 

AF1 = Abatement utilization factor of N2O abatemetechnology 1 (decimal fraction of time that abatement technology 1 is operating). 

V 98.223(g)(2) DF2 = Destruction efficiency of N2O abatement 

technology 2 (percent of N2O removed from vent stream). 

DF2 = Destruction efficiency of N2O abatement technology 2 (decimal fraction of N2O removed frovent stream). 

V 98.223(g)(2) AF2 = Abatement utilization factor of N2O abatement 

technology 2 (percent of time that abatement technology 2 is operating). 

AF2 = Abatement utilization factor of N2O abatemetechnology 2 (decimal fraction of time that abatement technology 2 is operating). 

V 98.223(g)(2) DFN = Destruction efficiency of N2O abatement 

technology N (percent of N2O removed from vent stream). 

DFN = Destruction efficiency of N2O abatement technology N (decimal fraction of N2O removed 

from vent stream). 

V 98.223(g)(2) AFN = Abatement utilization factor of N2O

abatement technology N (percent of time that abatement technology N is operating). 

AFN = Abatement utilization factor of N2Oabatement technology N (decimal fraction of time that abatement technology N is operating). 

V 98.223(g)(3) (3) If multiple N2O abatement technologies are 

located in parallel after your test point, you must use the emissions factor (determined in Equation V–1 of this section), the destruction efficiency (determined in paragraph (d) of this section), the annual nitric acid production (determined in paragraph (f) of this section), and the abatement utilization factor (determined in paragraph (e) of this section), according to Equation V–3c of this section: 

(3) If multiple N2O abatement technologies are located in parallel after your test point, you must uthe emissions factor (determined in Equation V–1 this section), the destruction efficiency (determined in paragraph (d) of this section), the annual nitric acid production (determined in paragraph (i) of thisection), and the abatement utilization factor (determined in paragraph (e) of this section), according to Equation V–3c of this section: 

V 98.223(g)(3) EN2Ot = Annual N2O mass emissions from nitric acid 

production unit “t” according to this Equation V–3c (metric tons). 

EN2Ot = Annual N2O mass emissions from nitric atrain “t” according to this Equation V–3c (metric tons). 

V 98.223(g)(3) EFN2O,t = N2O emissions factor for unit “t” (lb 

N2O/ton nitric acid produced). 

EFN2O,t = N2O emissions factor for nitric acid train “t” (lb N2O/ton nitric acid produced). 
33

Subpart Requirement Current Rule Text Proposed Rule Text 

V 98.223(g)(3) Pt = Annual nitric acid produced from unit “t” (ton 

acid produced, 100 percent acid basis). 

Pt = Annual nitric acid produced from nitric acid train “t” (ton acid produced, 100 percent acid basis

V 98.223(g)(3) DFN = Destruction efficiency of N2O abatement 

technology “N” (percent of N2O removed from vent 

stream). 

DFN = Destruction efficiency of N2O abatement technology “N” (decimal fraction of N2O removed from vent stream). 

V 98.223(g)(3) AFN = Abatement utilization factor of N2O

abatement technology “N” (percent of time that abatement technology “N” is operating). 

AFN = Abatement utilization factor of N2Oabatement technology “N” (decimal fraction of timthat abatement technology “N” is operating). 

V 98.223(g)(3) FCN = Fraction control factor of N2O abatement 

technology “N” (percent of total emissions from unit “t” that are sent to abatement technology “N”). 

FCN = Fraction control factor of N2O abatement technology “N” (decimal fraction of total emissionfrom nitric acid train “t” that are sent to abatement technology “N”). 

V 98.223(g)(4) EN2Ot = Annual N2O mass emissions from nitric acid 

production unit “t” according to this Equation V–3d (metric tons). 

EN2Ot = Annual N2O mass emissions from nitric atrain “t” according to this Equation V–3d (metric tons). 

V 98.223(i) (i) You must determine the total annual amount of 

nitric acid produced on nitric acid train “t” for each nitric acid train (tons acid produced, 100 percent acid basis), according to §98.224(f). 

(i) You must determine the total annual amount of nitric acid produced on each nitric acid train “t” (toacid produced, 100 percent acid basis), according t§98.224(f). 

V 98.224(c) (c) You must determine the production rate(s) (100 

percent basis) from each nitric acid train during the performance test according to paragraphs (c)(1) or (c)(2) of this section. 

(c) You must determine the production rate(s) (100 percent acid basis) from each nitric acid train durinthe performance test according to paragraphs (c)(1or (c)(2) of this section. 

V 98.224(e) (e) You must determine the total monthly amount of 

nitric acid produced. You must also determine the monthly amount of nitric acid produced while N2O 

abatement technology (located after the test point) is operating from each nitric acid train. These monthly amounts are determined according to the methods in paragraphs (c)(1) or (2) of this section. 

(e) You must determine the total monthly amount nitric acid produced. You must also determine the monthly amount of nitric acid produced while N2O 

abatement technology is operating from each nitric acid train. These monthly amounts are determined according to the methods in paragraphs (c)(1) or (2of this section. 

V 98.224(f) (f) You must determine the annual amount of nitric 

acid produced. You must also determine the annual amount of nitric acid produced while N2O abatement technology (located after the test point) is operating for each train. These annual amounts are determined by summing the respective monthly nitric acid quantities determined in paragraph (e) of this section. 

(f) You must determine the annual amount of nitric acid produced. You must also determine the annuaamount of nitric acid produced while N2O abatemetechnology is operating for each nitric acid train. These annual amounts are determined by summing the respective monthly nitric acid quantities determined in paragraph (e) of this section. 

V 98.226(a) (a) Train identification number. (a) Nitric Acid train identification number. 
34

Subpart Requirement Current Rule Text Proposed Rule Text 

V 98.226(n) (n) If you requested Administrator approval for an 

alternative method of determining N2O emissions under §98.223(a)(2), each annual report must also contain the information specified in paragraphs (n)(1) through (4) of this section. (n)(1) through (n)(4) of this section for each nitric acid production facility. 

(n) If you requested Administrator approval for an alternative method of determining N2O emissions under §98.223(a)(2), each annual report must also contain the information specified in paragraphs (n)(1) through (n)(4) of this section for each nitric acid production facility. 

V 98.226(o) (None) (o) [Reserved] V 98.226(p) (p) Fraction control factor for each abatement 

technology (percent of total emissions from the production unit that are sent to the abatement technology) if equation V–3c is used. 

(p) Fraction control factor for each abatement technology (percent of total emissions from the nitacid train that are sent to each abatement technologif Equation V–3c is used. 

X 98.242(b)(2) (2) If you comply with §98.243(c), report CO2, CH4, 

and N2O combustion emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C only for the combustion of supplemental fuel.  Determine the applicable Tier in subpart C of this part (General Stationary Fuel Combustion Sources) based on the maximum rated heat input capacity of the stationary combustion source. 

(2) If you comply with §98.243(c), report CO2, CHand N2O combustion emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart Cfor all fuels, except emissions from burning petrochemical process off-gas in any combustion unit are not to be reported under subpart C of this part. Determine the applicable Tier in subpart C othis part (General Stationary Fuel Combustion Sources) based on the maximum rated heat input capacity of the stationary combustion source. 

X 98.243(b) (b) Continuous emission monitoring system 

(CEMS). Route all process vent emissions and emissions from combustion of process off-gas to one or more stacks and determine CO2 emissions from each stack (except flare stacks) according to the Tier 4 Calculation Methodology requirements in subpart C of this part. For each stack (except flare stacks) that includes emissions from combustion of petrochemical process off-gas, calculate CH4 and 

N20 emissions in accordance with subpart C of this part (use the Tier 3 methodology, emission factors for “Petroleum” in Table C–2 of subpart C of this part, and either the default high heat value for fuel gas in Table C–1 of subpart C of this part or a calculated HHV, as allowed in Equation C–8 of subpart C of this part). For each flare, calculate CO2, 

(b) Continuous emission monitoring system (CEMS). Route all process vent emissions and emissions from stationary combustion units that buany amount of process off-gas to one or more stackand determine GHG emissions as specified in paragraphs (b)(1) through (3) of this section. (1)Determine CO2 emissions from each stack (exceflare stacks) according to the Tier 4 Calculation Methodology requirements in subpart C of this par(2)For each stack (except flare stacks) that includeemissions from combustion of petrochemical proceoff-gas, calculate CH4 and N2O emissions in accordance with subpart C of this part (use EquatioC-10 and the "fuel gas" emission factors in Table C2 of subpart C of this part). (3)For each flare, calculate CO2, CH4, and N2O 
35

Subpart Requirement Current Rule Text Proposed Rule Text 

CH4, and N2O emissions using the methodology specified in §98.253(b)(1) through (b)(3). 

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

X 98.243(c)(3) (3) Collect a sample of each feedstock and product at 

least once per month and determine the carbon content of each sample according to the procedures of §98.244(b)(4). If multiple valid carbon content measurements are made during the monthly measurement period, average them arithmetically. However, if a particular liquid or solid feedstock is delivered in lots, and if multiple deliveries of the same feedstock are received from the same supply source in a given calendar month, only one representative sample is required. Alternatively, you may use the results of analyses conducted by a fuel or feedstock supplier, provided the sampling and analysis is conducted at least once per month using any of the procedures specified in §98.244(b)(4). 

(3) Collect a sample of each feedstock and product least once per month and determine the carbon content of each sample according to the procedureof §98.244(b)(4). If multiple valid carbon content measurements are made during the monthly measurement period, average them arithmetically. However, if a particular liquid or solid feedstock is delivered in lots, and if multiple deliveries of the same feedstock are received from the same supply source in a given calendar month, only one representative sample is required. Alternatively, yomay use the results of analyses conducted by a feedstock supplier, or product customer, provided sampling and analysis is conducted at least once pemonth using any of the procedures specified in §98.244(b)(4). 

X 98.243(c)(4) (4) If you determine that the monthly average 

concentration of a specific compound in a feedstock or product is greater than 99.5 percent by volume (or mass for liquids and solids), then as an alternative to the sampling and analysis specified in paragraph (c)(3) of this section, you may calculate the carbon content assuming 100 percent of that feedstock or product is the specific compound during periods of normal operation. This alternative may not be used for products during periods of operation when offspecification product is produced. You must maintain records of any determination made in accordance with this paragraph (c)(4) along with all supporting data, calculations, and other information. You must reevaluate determinations made under this paragraph (c)(4) after any process change that affects the feedstock or product composition. You must keep records of the process change and the corresponding composition determinations. If the feedstock or product composition changes so that the average monthly concentration falls below 99.5 

(4) If you determine that the monthly average concentration of a specific compound in a feedstocor product is greater than 99.5 percent by volume omass, then as an alternative to the sampling and analysis specified in paragraph (c)(3) of this sectioyou may determine carbon content in accordance with paragraphs (c)(4)(i) through (iii) of this sectio(i) Calculate the carbon content assuming 100 percent of that feedstock or product is the specific compound. (ii) You must maintain records of any determinatiomade in accordance with this paragraph (c)(4) alonwith all supporting data, calculations, and other information. (iii) Reevaluate determinations made under this paragraph (c)(4) after any process change that affethe feedstock or product composition. Keep recordof the process change and the corresponding composition determinations. If the feedstock or product composition changes so that the average monthly concentration falls below 99.5 percent, yo
36

Subpart Requirement Current Rule Text Proposed Rule Text 

percent, you are no longer permitted to use this alternative method. 

are no longer permitted to use this alternative method. 

X 98.243(c)(5)(i

) 

Cg = Annual net contribution to calculated emissions from carbon (C ) in gaseous materials (kilograms/year, kg/yr) (Fgf)i,n = Volume of gaseous feedstock i introduced in month "n" (standard cubic feet, scf ). (MWf)i = Molecular weight of gaseous feedstock i (kg/kg-mole). (Pgp)i,n = volume of gaseous product i produced in month "n" (scf). (MWp)i,n = Molecular wieght of gaseous product i (kg/kg-mole). 

Cg = Annual net contribution to calculated emissiofrom carbon (C ) in gaseous materials, including streams containing CO2 recovered for sale or use in another process( kg/yr) (Fgf) = Volume or mass of gaseous feedstock i introduced in month "n" (scf or kg). If you measurmass, the term (MWf)i/MVC is replaced with "1". (MWf)i,n = Molecular weight of gaseous feedstock in month "n" (kg/kg-mole). (Pgp)i,n = Volume or mass of gaseous product i produced in month "n" (scf or kg). If you measure mass, the term (MWp)i/MVC is replaced with "1". (MWp)i,n = Molecular wieght of gaseous product i imonth "n" (kg/kg-mole). 

X 98.243(d)(3)(

i) 

(i) For all gaseous fuels that contain ethylene process off-gas, use the emission factors for "Petroleum" in Table C–2 of subpart C of this part (General Stationary Fuel Combustion Sources). 

(i) For all gaseous fuels that contain ethylene proceoff-gas, use the emission factors for "Fuel Gas" in Table C–2 of subpart C of this part (General Stationary Fuel Combustion Sources). 

X 98.244(b)(4) (4) ...Analyses conducted in accordance with 

methods specified in paragraphs (b)(4)(i) through (b)(4)(xv) of this section may be performed by the owner or operator, by an independent laboratory, or by the supplier of a feedstock. 

(4) ...Analyses conducted in accordance with methods specified in paragraphs (b)(4)(i) through (b)(4)(xv) of this section may be performed by the owner or operator, by an independent laboratory, bthe supplier of a feedstock, or by a product custom

X 98.244(b)(4)(

xiii) 

(xiii) The results of chromatographic analysis of a feedstock or product, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions. 

(xiii) The results of chromatographic analysis of a feedstock or product, provided that the chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions. 

X 98.244(b)(4)(

xiv) 

(xiv) The carbon content results of mass spectrometer analysis of a feedstock or product, provided that the mass spectrometer is operated, maintained, and calibrated according to the manufacturer's instructions. 

(xiv) The results of mass spectrometer analysis of feedstock or product, provided that the mass spectrometer is operated, maintained, and calibrateaccording to the manufacturer's instructions. 

X 98.244(b)(4)(

xv)(A) 

(A) An industry standard practice for carbon black feedstock oils and carbon black products. 

(A) An industry standard practice, or a method published by a consensus-based standards organization if such a method exists, for carbon black feedstock oils and carbon black products. 
37

Subpart Requirement Current Rule Text Proposed Rule Text 

Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 181L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org ), the AmericGas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 8247000, http://www.aga.org ), the American Society Mechanical Engineers (ASME, Three Park AvenueNew York, NY 10016-5990, (800) 843-2763, http://www.asme.org ), the American Petroleum Institute (API, 1220 L Street, NW., Washington, D20005-4070, (202) 682-8000, http://www.api.org )and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.naesb.org)The method(s) used shall be documented in the Monitoring Plan required under § 98.3(g)(5). 

X 98.244(c) (None) (c) If you comply with §98.243(b) or (d), conduct 

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

X 98.245

Introductory paragraph 

For missing feedstock flow rates, product flow rates, and carbon contents, use the same procedures as for missing flow rates and carbon contents for fuels as specified in §98.35. 

For missing feedstock and product flow rates, usethe same procedures as for missing fuel usage as specified in §98.35(b)(2). For missing feedstock aproduct carbon contents and missing molecular weights for gaseous feedstocks and products, use tsame procedures as for missing carbon contents anmissing molecular weights for fuels as specified in §98.35(b)(1). For missing flare data, follow the procedures in §98.255(b) and (c). 

X 98.246(a)(6) (6) Name of each method listed in §98.244 used to 

determine a measured parameter (or description of manufacturer's recommended method). 

(6) For each feedstock and product, provide the information specified in paragraphs (a)(6)(i) throug(a)(6)(iii) of this section. (i) Name of each method used to determine carbon content or molecular weight in accordance with 98.244(b)(4); 
38

Subpart Requirement Current Rule Text Proposed Rule Text 

(ii) Description of each type of device (e.g., flow meter, weighing device) used to determine flow or mass in accordance 98.244(b)(1) through (3). (iii) Identification of each method (i.e., method number, title, or other description) used to determiflow or mass in accordance with 98.244(b)(1) through (3).

X 98.246(a)(8) (8) Identification of each combustion unit that 

burned both process off-gas and supplemental fuel. 

(8) Identification of each combustion unit that burned both process off-gas and supplemental fuelincluding combustion units that are not part of the petrochemical process unit. 

X 98.246(a)(9) (9) If you comply with the alternative to sampling 

and analysis specified in §98.243(c)(4), the amount of time during which off-specification product was produced, the volume or mass of off-specification product produced, and if applicable, the date of any process change that reduced the composition to less than 99.5 percent. 

(9) If you comply with the alternative to sampling and analysis specified in §98.243(c)(4), the numbeof days during which off-specification product was produced, and if applicable, the date of any proceschange that reduced the composition to less than 9percent. 

X 98.246(a)(11) (11) If you determine carbon content or composition 

of a feedstock or product using a method under §98.244(b)(4)(xv)(B), report the information listed in paragraphs (a)(11)(i) through (a)(11)(iv) of this section. 

(11) If you determine carbon content or compositioof a feedstock or product using a method under §98.244(b)(4)(xv)(B), report the information listed paragraphs (a)(11)(i) through (a)(11)(iii) of this section. 

X 98.246(b)(2) (2) For CEMS used on stacks for stationary 

combustion units, report the relevant information required under §98.36 for the Tier 4 calculation methodology. Section 98.36(b)(9)(iii) does not apply for the purposes of this subpart. 

(2) For CEMS used on stacks that include emissionfrom stationary combustion units that burn any amount of off-gas from the petrochemical process, report the relevant information required under §98.36(c)(2) and (e)(2)(vi) for the Tier 4 calculatiomethodology. Sections §98.36(c)(2)( ii) and (c)(2)(ix) do not apply for the purposes of this subpart. 

X 98.246(b)(3) (3) For CEMS used on stacks that are not used for 

stationary combustion units, report the information required under §98.36(e)(2)(vi). 

(3) For CEMS used on stacks that do not include emissions from stationary combustion units, report the information required under §98.36(b)(6), (b)(7and §98.36(e)(2)(vi). 
39

Subpart Requirement Current Rule Text Proposed Rule Text 

X 98.246(b)(4) (4) The CO2 emissions from each stack and the 

combined CO2 emissions from all stacks (except flare stacks) that handle process vent emissions and emissions from stationary combustion units that burn process off-gas for the petrochemical process unit. For each stationary combustion unit (or group of combustion units monitored with a single CO2

CEMS) that burns petrochemical process off-gas, provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off-gas from the petrochemical process unit. 

(4) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) or (3) of this section, provide an estimate based on engineering judgment of the fraction of the total CO2 emissions 

that is attributable to the petrochemical process uni

X 98.246(b)(5) (5) For stationary combustion units that burn process 

off-gas from the petrochemical process unit, report the information related to CH4 and N2O emissions as specified in paragraphs (b)(5)(i) through (b)(5)(iv) of this section. (i) The CH4 and N2O emissions from each stack that 

is monitored with a CO2 CEMS, expressed in metric tons of each gas and in metric tons of CO2 e. For each stack provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off-gas from the petrochemical process unit. (ii) The combined CH4 and N2O emissions from all stationary combustion units, expressed in metric tons of each gas and in metric tons of CO2 e. (iii) The quantity of each type of fuel used in Equation C–8 in §98.33(c) for each stationary combustion unit or group of units (as applicable) during the reporting year, expressed in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels. (iv) The HHV (either default or annual average from 

(5) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) of this section, report the CH4 and N2O emissions expressed in metric tons of each gas. For each CEMS monitorinlocation, provide an estimate based on engineering judgment of the fraction of the total CH4 and N2O 

emissions that is attributable to combustion of offgas from the petrochemical process unit. (i)[Reserved] (ii)[Reserved] (iii)[Reserved] (iv)[Reserved] 
40

Subpart Requirement Current Rule Text Proposed Rule Text 

measured data) used in Equation C–8 in §98.33(c) for each stationary combustion unit or group of combustion units (as applicable). 

X 98.246(b)(6) (6) ID or other appropriate descriptor of each 

stationary combustion unit that burns process offgas. 

(6) [Reserved] 

X 98.246(c)(4) (4) Name and annual quantity of each feedstock (4) Name and annual quantity of each feedstock 

(metric tons). 

X 98.247(b) (b) If you comply with the mass balance 

methodology in §98.243(c), then you must retain records of the information listed in paragraphs (b)(1) through (b)(3) of this section. (1) Results of feedstock or product composition determinations conducted in accordance with §98.243(c)(4). (2) Start and end times and calculated carbon contents for time periods when off-specification product is produced, if you comply with the alternative methodology in §98.243(c)(4) for determining carbon content of feedstock or product. 

(b) If you comply with the mass balance methodology in §98.243(c), then you must retain records of the information listed in paragraphs (b)(through (b)(4) of this section. (1) Results of feedstock or product composition determinations conducted in accordance with §98.243(c)(4). (2) Start and end times for time periods when offspecification product is produced, if you comply with the alternative methodology in §98.243(c)(4) for determining carbon content of product. 

X 98.248 Product, as used in §98.243, means each of the 

following carbon-containing outputs from a process: the petrochemical, recovered byproducts, and liquid organic wastes that are not incinerated onsite. Product does not include process vent emissions, fugitive emissions, or wastewater. 

Product, as used in §98.243, means each of the following carbon-containing outputs from a procesthe petrochemical, recovered byproducts, and liquiorganic wastes that are not combusted onsite. Product does not include process vent emissions, fugitive emissions, or wastewater. 

Y 98.252(a) (a) .... For CH4 and N2O emissions from combustion 

of fuel gas, use the applicable procedures in 98.33 (c ) for the same tier methodology that was used for calculating CO2 emissions. (Use the default CH4 and N2O emission factors for "Petroleum (All fuel types in Table C-1)" in Table C-2 of this part. For Tier 3... 

(a) .... For CH4 and N2O emissions from combustiof fuel gas, use the applicable procedures in 98.33(for the same tier methodology that was used for calculating CO2 emissions. (Use the default CH4 anN2O emission factors for "Fuel Gas" in Table C-2 this part. For Tier 3.... 

Y 98.252(i) (i) CO2 emissions from non-merchant hydrogen 

production process units (not including hydrogen produced from catalytic reforming units) under this subpart. You must follow the calculation methodologies, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of subpart P of this part. 

(i) CO2 emissions from non-merchant hydrogen production process units (not including hydrogen produced from catalytic reforming units) following the calculation methodologies, monitoring and QA/QC methods, missing data procedures, reportinrequirements, and recordkeeping requirements of subpart P of this part. 
41

Subpart Requirement Current Rule Text Proposed Rule Text 

Y 98.253(b)(2) EmFCH4 = Default CH4 emission factor for 

"PetroleumProducts" from Table C-2 of Subpart C of this part (General Staionary Fuel Combusion Sources) (kg CH4/ MMBtu) 

EmFCH4 = Default CH4 emission factor for "Fuel Gas" from Table C-2 of Subpart C of this part (General Staionary Fuel Combusion Sources) (kg CH4/ MMBtu) 

Y 98.253(b)(3) EmFN2O = Default N2O emission factor for 

"PetroleumProducts" from Table C-2 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg N2O/MMBtu). 

EmFN2O = Default N2O emission factor for "Fuel Gas" from Table C-2 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg N2O/MMBtu). 

Y 98.253(f)(2) (2) Flow measurement. If you have a continuous 

flow monitor on the sour gas feed to the sulfur recovery plant, you must use the measured flow rates when the monitor is operational to calculate the sour gas flow rate. If you do not have a continuous flow monitor on the sour gas feed to the sulfur recovery plant, you must use engineering calculations, company records, or similar estimates of volumetric sour gas flow. 

(2) Flow measurement. If you have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use the measured flow rates when the monitor is operational to calculate tsour gas flow rate. If you do not have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use engineering calculations, company records, or similar estimates of volumetric sour gas flow. 

Y 98.253(f)(3) (3) Carbon content. If you have a continuous gas 

composition monitor capable of measuring carbon content on the sour gas feed to the sulfur recovery plant or if you monitor gas composition for carbon content on a routine basis, you must use the measured carbon content value. Alternatively, you may develop a site-specific carbon content factor using limited measurement data or engineering estimates or use the default factor of 0.20. 

(3) Carbon content. If you have a continuous gas composition monitor capable of measuring carbon content on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site for sulfurecovery, or if you monitor gas composition for carbon content on a routine basis, you must use the measured carbon content value. Alternatively, you may develop a site-specific carbon content factor using limited measurement data or engineering estimates or use the default factor of 0.20. 

Y 98.253(f)(4) (4) Calculate the CO2 emissions from each sulfur 

recovery plant using Equation Y–12 of this section. Where: FSG = Volumetric flow rate of sour gas feed (including sour water stripper gas) to the sulfur recovery plant (scf/year). MFC = Mole fraction of carbon in the sour gas to the sulfur recovery plant (kg-mole C/kg-mole gas); default = 0.20. 

(4) Calculate the CO2 emissions from each on-site sulfur recovery plant and for sour gas sent off-site sulfur recovery using Equation Y–12 of this sectioWhere: FSG = Volumetric flow rate of sour gas (including sour water stripper gas)fed to the sulfur recovery plant or the sour gas feed sent for off-site for sulfurecovery (scf/year). MFC = Mole fraction of carbon in the sour gas fed the sulfur recovery plant or the sour gas feed sent f
42

Subpart Requirement Current Rule Text Proposed Rule Text 

off-site for sulfur recovery (kg-mole C/kg-mole gadefault = 0.20. 

Y 98.253(j) (j) For each process vent not covered in paragraphs 

(a) through (i) of this section that can reasonably be expected to contain greater than 2 percent by volume CO2 or greater than 0.5 percent by volume of CH4 or greater than 0.01 percent by volume (100 parts per million) of N2O, calculate GHG emissions using the Equation Y–19 of this section. You must use Equation Y–19 of this section to calculate CH4

emissions for catalytic reforming unit depressurization and purge vents when methane is used as the purge gas or if you elected this method as an alternative to the methods in paragraphs (f), (h), or (k) of this section. 

(j) For each process vent not covered in paragraph(a) through (i) of this section that can reasonably bexpected to contain greater than 2 percent by volumCO2 or greater than 0.5 percent by volume of CH4 greater than 0.01 percent by volume (100 parts per million) of N2O, calculate GHG emissions using thEquation Y–19 of this section. You must also use Equation Y–19 of this section to calculate CH4

emissions for catalytic reforming unit depressurization and purge vents when methane is used as the purge gas, CH4 emissions if you elected to use the method in (i)(1) of this section, and CO2and/or CH4 emissions, as applicable, if you elected this method as an alternative to the methods in paragraphs (f), (h), or (k) of this section. 

Y 98.253(k) (k) For uncontrolled blowdown systems, you must 

calculate CH4 emissions either using the methods for process vents in paragraph (j) of this section regardless of the CH4concentration or using Equation Y20 of this section. Blowdown systems where the uncondensed gas stream is routed to a flare or similar control device is considered to be controlled and is not required to estimate emissions under this paragraph (k). 

(k) For uncontrolled blowdown systems, you must calculate CH4 emissions either using the methods fprocess vents in paragraph (j) of this section regardless of the CH4concentration or using EquatiY-20 of this section. Blowdown systems where thuncondensed gas stream is routed to a flare or simicontrol device is considered to be controlled and is not required to estimate emissions under this paragraph (k). 

Y 98.253(m) (m) For storage tanks, except as provided in 

paragraph (m)(4) of this section, calculate CH4

emissions using the applicable methods in paragraphs (m)(1) through (m)(3) of this section. 

(m) For storage tanks, except as provided in paragraph (m)(3) of this section, calculate CH4

emissions using the applicable methods in paragraphs (m)(1) and (m)(2) of this section. 

Y 98.256(f)(6) (6) If you use a CEMS, the relevant information 

required under §98.36 for the Tier 4 Calculation Methodology, the CO2 annual emissions as measured 

by the CEMS (unadjusted to remove CO2

combustion emissions associated with additional units, if present) and the process CO2 emissions as 

calculated according to §98.253(c)(1)(ii). Report the CO2 annual emissions associated with sources other than those from the coke burn-off in the applicable 

(6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology, the CO2 annual emissions as measurby the CEMS (unadjusted to remove CO2combustion emissions associated with additional units, if present) and the process CO2 emissions as 

calculated according to §98.253(c)(1)(ii). Report thCO2 annual emissions associated with sources othethan those from the coke burn-off in accordance w
43

Subpart Requirement Current Rule Text Proposed Rule Text 

subpart (e.g., subpart C of this part in the case of a CO boiler). 

the applicable subpart (e.g., subpart C of this part ithe case of a CO boiler). 

Y 98.256(h) (h) For sulfur recovery plants and for emissions from 

sour gas sent off-site for sulfur recovery, the owner and operator shall report: 

(h) For on-site sulfur recovery plants and for emissions from sour gas sent off-site for sulfur recovery, the owner and operator shall report: 

Y 98.256(h)(2) (2) Maximum rated throughput of each independent 

sulfur recovery plant, in metric tons sulfur produced/stream day, a description of the type of sulfur recovery plant, and an indication of the method used to calculate CO2 annual emissions for the sulfur recovery plant (e.g., CO2 CEMS, Equation Y–12, or process vent method in §98.253(j)). 

(2) For each on-site sulfur recovery plant, the maximum rated throughput (metric tons sulfur produced/stream day), a description of the type of sulfur recovery plant, and an indication of the method used to calculate CO2 annual emissions for the sulfur recovery plant (e.g., CO2 CEMS, EquatiY–12, or process vent method in §98.253(j)). 

Y 98.256(h)(3) (3) The calculated CO2 annual emissions for each 

sulfur recovery plant, expressed in metric tons. The calculated annual CO2 emissions from sour gas sent off-site for sulfur recovery, expressed in metric tons. 

(3) The calculated CO2 annual emissions for each on-site sulfur recovery plant, expressed in metric tons. The calculated annual CO2 emissions from so

gas sent off-site for sulfur recovery, expressed in metric tons. 

Y 98.256(h)(4) (4) If you use Equation Y–12 of this subpart, the 

annual volumetric flow to the sulfur recovery plant (in scf/year), the molar volume conversion factor (in scf/kg-mole), and the annual average mole fraction of carbon in the sour gas (in kg-mole C/kg-mole gas). 

(4) If you use Equation Y–12 of this subpart, the annual volumetric flow to the on-site and off-site sulfur recovery plant (in scf/year), the molar volumconversion factor (in scf/kg-mole), and the annual average mole fraction of carbon in the sour gas (in kg-mole C/kg-mole gas). 

Y 98.256(h)(5) (5) If you recycle tail gas to the front of the sulfur 

recovery plant, indicate whether the recycled flow rate and carbon content are included in the measured data under §98.253(f)(2) and (3). Indicate whether a correction for CO2 emissions in the tail gas was used in Equation Y–12. If so, then report the value of the correction, the annual volume of recycled tail gas (in scf/year) and the annual average mole fraction of carbon in the tail gas (in kg-mole C/kg-mole gas). Indicate whether you used the default (95%) or a unit specific correction, and if used, report the approach used. 

(5) If you recycle tail gas to the front of an on-site sulfur recovery plant, indicate whether the recycled flow rate and carbon content are included in the measured data under §98.253(f)(2) and (3). Indicatwhether a correction for CO2 emissions in the tail gwas used in Equation Y–12. If so, then report the value of the correction, the annual volume of recycled tail gas (in scf/year) and the annual averagmole fraction of carbon in the tail gas (in kg-mole C/kg-mole gas). Indicate whether you used the default (95%) or a unit specific correction, and if a unit specific correction is used, report the approach used. 

Y 98.256(h)(6) (6) If you use a CEMS, the relevant information 

required under §98.36 for the Tier 4 Calculation Methodology, the CO2 annual emissions as measured 

(6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology, the CO2 annual emissions as measur
44

Subpart Requirement Current Rule Text Proposed Rule Text 

by the CEMS and the annual process CO2 emissions calculated according to §98.253(f)(1). Report the CO2 annual emissions associated with fuel combustion subpart C of this part (General Stationary Fuel Combustion Sources). 

by the CEMS and the annual process CO2 emissioncalculated according to §98.253(f)(1). Report the CO2 annual emissions associated with fuel combustion in accordance with subpart C of this p(General Stationary Fuel Combustion Sources). 

Y 98.256(j) (10) (None) (10)If you use Equation Y-19 of this subpart, the 

relevant information required under paragraph (l)(5of this section. 

Y 98.256(k)(4) (4) For each set of coking drums that are the same 

dimensions: The number of coking drums in the set, the height and diameter of the coke drums (in feet), the cumulative number of vessel openings for all delayed coking drums in the set, the typical venting pressure (in psig), void fraction (in cf gas/cf of vessel), and the mole fraction of methane in coking gas (in kg-mole CF4/kg-mole gas, wet basis). 

(4) For each set of coking drums that are the same dimensions: The number of coking drums in the sethe height and diameter of the coke drums (in feet)the cumulative number of vessel openings for all delayed coking drums in the set, the typical ventinpressure (in psig), void fraction (in cf gas/cf of vessel), and the mole fraction of methane in coking gas (in kg-mole CH4/kg-mole gas, wet basis). 

Y 98.256(k)(6) (None) (6) If you use Equation Y-19 of this subpart, the 

relevant information required under paragraph (l)(5of this section for each set of coke drums or vesselof the same size. 

Y 98.256(o)(4)(

vi) 

(vi) If you did not use Equation Y–23, the tank- specific methane composition data and the gas generation rate data used to estimate the cumulative CH4 emissions for storage tanks used to process unstabilized crude oil. 

(vi) If you did not use Equation Y–23, the tank- specific methane composition data and the annual gas generation volume (scf/yr) used to estimate the cumulative CH4 emissions for storage tanks used tprocess unstabilized crude oil. 

Y 98.256(o)(5), 

(6), (7) 

(5) The method used to calculate the reported storage tank emissions for storage tanks processing unstabilized crude oil. (6) The quantity of unstabilized crude oil received during the calendar year (in MMbbl), the average pressure differential (in psi), and the mole fraction ofCH4 in vent gas from the unstabilized crude oil storage tank, and the basis for the mole fraction. (7) The tank-specific methane composition data and the gas generation rate data, if you did not use Equation Y–23. 

(5) [Reserved][6) [Reserved] (7) [Reserved] 

Z 98.263(b)(1)(

ii) 

(ii) If your process measurement provides the CO2emissions directly as an output...CO2 n,i = Carbon dioxide emissions of a grab sample 

(ii) If your process measurement provides the CO2content directly as an output...CO2 n,i = Carbon dioxide content of a grab sample 
45

Subpart Requirement Current Rule Text Proposed Rule Text 

batch of phosphate rock by origin i obtained during month n (percent by weight, expressed as a decimal fraction). 

batch of phosphate rock by origin i obtained during month n (percent by weight, expressed as a decimafraction). 

Z 98.264(a) (a) You must obtain a monthly grab sample of 

phosphate rock directly from the rock being fed to the process line before it enters the mill using one of the following methods. You may conduct the representative bulk sampling using a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists (AFPC) (P.O. Box 1645, Bartow, Florida 33831, (863) 534–9755, http://afpc.net, paul.mcafee@mosaicco.com). If phosphate rock is 

obtained from more than one origin in a month, you must obtain a sample from each origin of rock or obtain a composite representative sample. 

(a) You must obtain a monthly grab sample of phosphate rock directly from the rock being fed to the process line before it enters the mill using one the following methods. You may conduct the representative bulk sampling using a method published by a consensus standards organization, oyou may use industry consensus standard practice methods, including but not limited to the PhosphatMining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists (AFPC). If phosphate rock is obtained from more than one origin in a month, you must obtain a sampfrom each origin of rock or obtain a composite representative sample. 

Z 98.264(b) (b) You must determine the carbon dioxide or 

inorganic carbon content of each monthly grab sample of phosphate rock (consumed in the production of phosphoric acid). You may use a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by AFPC (P.O. Box 1645, Bartow, Florida 33831, (863) 534–9755, http://afpc.net, paul.mcafee@mosaicco.com). 

(b) You must determine the carbon dioxide or inorganic carbon content of each monthly grab sample of phosphate rock (consumed in the production of phosphoric acid). You may use a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limiteto the Phosphate Mining States Methods Used and Adopted by AFPC. 

Z 98.265(a) (a) For each missing value of the inorganic carbon 

content of phosphate rock or carbon dioxide (by origin), you must use the appropriate default factor provided in Table Z–1 this subpart. Alternatively, you must determine a substitute data value by calculating the arithmetic average of the qualityassured values of inorganic carbon contents of phosphate rock of origin i from samples immediately preceding and immediately following the missing 

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter must be used in thcalculations as specified in paragraphs (a) and (b) othis section. (a) For each missing value of the inorganic carbon content or CO2 content of phosphate rock (by origi
46

Subpart Requirement Current Rule Text Proposed Rule Text 

data incident. You must document and keep records of the procedures used for all such estimates. (a) For each missing value of the inorganic carbon content of phosphate rock (by origin), you must use the appropriate default factor provided in Table Z–1 of this subpart. Alternatively, the you must determine substitute data value by calculating the arithmetic average of the quality-assured values of inorganic carbon contents of phosphate rock of origin i (see Equation Z–1 of this subpart) from samples immediately preceding and immediately following the missing data incident. If no quality-assured data on inorganic carbon contents of phosphate rock of origin i are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for inorganic carbon contents for phosphate rock of origin i obtained after the missing data period. 

you must use the appropriate default factor providein Table Z–1 of this subpart. Alternatively, you mdetermine a substitute data value by calculating the arithmetic average of the quality-assured values of inorganic carbon contents or CO2 contents of phosphate rock of origin i (see Equation Z–1a or Z1b of this subpart) from samples immediately preceding and immediately following the missing data incident. If no quality-assured data on inorgancarbon contents or CO2 contents of phosphate rock of origin i are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for inorganic carbon contentor CO2 contents for phosphate rock of origin i obtained after the missing data period. 

Z 98.266(a) (a) Annual phosphoric acid production by origin (as 

listed in Table Z–1 to this subpart) of the phosphate rock (tons). 

(a) Annual phosphoric acid production, by origin othe phosphate rock (tons). 

Z 98.266(b) (b) Annual phosphoric acid permitted production 

capacity (tons) 

(b) Annual phosphoric acid production capacity (tons) 

Z 98.266(d) (d) Annual phosphate rock consumption from 

monthly measurement records by origin, (as listed in Table Z–1 to this subpart) (tons). 

(d) Annual phosphate rock consumption from monthly measurement records by origin (tons). 

Z 98.266(f)(5) (5) Monthly inorganic carbon content of phosphate 

rock for each wet-process phosphoric acid process line for which Equation Z–1a is used (percent by weight, expressed as a decimal fraction), or CO2

(percent by weight, expressed as a decimal fraction) for which Equation Z–1b is used. 

(5) Monthly inorganic carbon content of phosphate rock for each wet-process phosphoric acid process line for which Equation Z–1a is used (percent by weight, expressed as a decimal fraction), or CO2

content (percent by weight, expressed as a decimal fraction) for which Equation Z–1b is used. 

Z 98.266(f)(6) (6) Monthly mass of phosphate rock consumed by 

origin, (as listed in Table Z–1 of this subpart) in production for each wet-process phosphoric acid process line (tons). 

(6) Monthly mass of phosphate rock consumed, by origin, in production for each wet-process phosphoric acid process line (tons). 

Z 98.266(f)(8) (8) Number of times missing data procedures were 

used to estimate phosphate rock consumption (months) and inorganic carbon contents of the 

(8) Number of times missing data procedures were used to estimate phosphate rock consumption (months), inorganic carbon contents of the phosph
47

Subpart Requirement Current Rule Text Proposed Rule Text 

phosphate rock (months). rock (months), and CO2 contents of the phosphate 

rock (months). 

Z 98.267(a) (a) Monthly mass of phosphate rock consumed by 

origin (as listed in Table Z–1 of this subpart) (tons). 

(a) Monthly mass of phosphate rock consumed by origin (tons). 

Z 98.26(c ) (c) Documentation of the procedures used to ensure 

the accuracy of monthly phosphate rock consumption by origin, (as listed in Table Z–1 of this subpart). 

(c) Documentation of the procedures used to ensurthe accuracy of monthly phosphate rock consumption by origin. 

AA 98.273(a)(3) (3) Calculate biogenic CO2 emissions and emissions 

of CH4 and N2O from biomass using measured quantities of spent liquor solids fired, site-specific HHV, and default or site-specific emissions factors, according to Equation AA–1 of this section: *** (Variable from Equation AA-1:) (EF) = Default or site-specific emission factor for CO2, CH4, or N2O, from Table AA–1 of this subpart 

(kg CO2, CH4, or N2O per mmBtu). 

(3) Calculate biogenic CO2 emissions and emissionof CH4 and N2O from biomass using measured quantities of spent liquor solids fired, site-specific HHV, and default emissions factors, according to Equation AA–1 of this section: *** (Variable from Equation AA-1:) (EF) = Default emission factor for CO2, CH4, or N2O, from Table AA–1 of this subpart (kg CO2, CH

or N2O per mmBtu). 

AA 98.276(e) (e) The default or site-specific emission factor for 

CO2, CH4, or N2O, used in Equation AA–1 of this 

subpart (kg CO2, CH4, or N2O per mmBtu). 

(e) The default emission factor for CO2, CH4, or N2O, used in Equation AA–1 of this subpart (kg CO2, CH4, or N2O per mmBtu). 

AA 98.276(k) (k) Annual production of pulp and/or paper products 

produced (metric tons). 

(k) Annual production of pulp and/or paper producproduced (metric tons) as follows: (1) Report the total annual production of unbleachevirgin pulp produced onsite during the reporting yein air-dried metric tons per year. This total annual production value is the sum of all kraft, semichemical, soda, and sulfite pulp produced onsprior to bleaching, through all virgin pulping lines. (i) Do not include secondary fiber repulped for papproduction in the virgin pulp production total. (ii) You must report a positive (non-zero) value for pulp production unless your pulp mill did not operduring the reporting year. (2) Report the total annual production of paper products exiting the paper machine(s), prior to application of any off-machine coatings, in air-drie
48

Subpart Requirement Current Rule Text Proposed Rule Text 

metric tons per year. If you operate multiple paper machines, report the sum (total) of the air-dried metric tons of paper produced during the reporting year for all paper machines at the mill. 

AA Tables AA-1 

& AA-2 

See Tables AA-1 and AA-2 in the current rule file. See Appendix A for changes to Table AA-1 and A

2 

BB 98.282(a) (a) CO2 and CH4 process emissions from all silicon 

carbide process units or furnaces combined. 

(a) CO2 process emissions from all silicon carbide process units or furnaces combined. 

BB 98.283

Introductory paragraph 

98.283 Calculating GHG Emissions. You must calculate and report the annual process CO2 emissions from each silicon carbide process unit or production furnace using the procedures in either paragraph (a) or (b) of this section. You must determine CH4 process emissions in accordance with the procedures specified in paragraph (d) of this section. 

98.283 Calculating GHG Emissions. You must calculate and report the combined annuaprocess CO2 emissions from all silicon carbide process units and production furnaces using the procedures in either paragraph (a) or (b) of this section. 

BB 98.283(a) (a) Calculate and report under this subpart the 

process CO2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). 

(a) Calculate and report under this subpart the combined annual process CO2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Ti4 in subpart C of this part (General Stationary Fuel Combustion Sources). 

BB 98.283(b) (b) Calculate and report under this subpart the 

process CO2 emissions using the procedures in paragraphs (b)(1) and (b)(2) of this section. 

(b) Calculate and report under this subpart the combined annual process CO2 emissions using the procedures in paragraphs (b)(1) and (b)(2) of this section. 

BB 98.283(b)(2) (2) Use Equation BB–2 of this section to calculate 

annual CO2 process emissions from all silicone carbide production: 

(2) Calculate annual CO2 process emissions from tsilicon carbide production facility according to Equation BB-2 of this section: 

BB 98.283(b)(2) Tn = Petroleum coke consumption in month n(tons) Tn = Petroleum coke consumption in calendar mon

n(tons) 

BB 98.283(d) (d) You must calculate annual process CH4

emissions from all silicon carbide production combined using Equation BB–3 of this section: Eq. BB-3 

(d) [Reserved] 

BB 98.286(b) (b) If a CEMS is not used to measure process CO2

emissions, you must report the information listed in 

(b) If a CEMS is not used to measure process CO2emissions, you must report the information in 
49

Subpart Requirement Current Rule Text Proposed Rule Text 

this paragraph (b) for all furnaces combined: paragraph (b)(1) through (b)(8) of this section for a

silicon carbide process units or production furnacecombined: 

DD 98.304(c)(1) (1) Ensure that cylinders returned to the gas supplier 

are consistently weighed on a scale that is certified to be accurate and precise to within 2 pounds of the scale's capacity and is periodically recalibrated per the manufacturer's specifications. Either measure residual gas (the amount of gas remaining in returned cylinders) or have the gas supplier measure it. If the gas supplier weighs the residual gas, obtain from the gas supplier a detailed monthly accounting, within ± 2 pounds, of residual gas amounts in the cylinders returned to the gas supplier. 

(1) Ensure that cylinders returned to the gas suppliare consistently weighed on a scale that is certified be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer's specifications. Either measure residual gas (the amount of gas remaining in returncylinders) or have the gas supplier measure it. If thgas supplier weighs the residual gas, obtain from thgas supplier a detailed monthly accounting, within 2 pounds, of residual gas amounts in the cylinders returned to the gas supplier. 

DD 98.304(c)(2) (2) Ensure that cylinders weighed for the beginning 

and end of year inventory measurements are weighed on a scale that is certified to be accurate to within 2 pounds of the scale's capacity and is periodically recalibrated per the manufacturer's specifications. All scales used to measure quantities that are to be reported under §98.306 must be calibrated using calibration procedures specified by the scale manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer. 

(2) Ensure that cylinders weighed for the beginninand end of year inventory measurements are weighon a scale that is certified to be accurate and precisto within 2 pounds of true weight and is periodicalrecalibrated per the manufacturer's specifications. Ascales used to measure quantities that are to be reported under §98.306 must be calibrated using calibration procedures specified by the scale manufacturer. Calibration must be performed prior the first reporting year. After the initial calibrationrecalibration must be performed at the minimum frequency specified by the manufacturer. 

FF 98.320(b)(1) (1) Each ventilation well or shaft, including both 

those wells and shafts where gas is emitted and those where gas is sold, used onsite, or otherwise destroyed (including by flaring). 

(1) Each ventilation system shaft or vent hole, including both those points where mine ventilation air is emitted and those where it is sold, used onsitor otherwise destroyed (including by ventilation aimethane (VAM) oxidizers). 

FF 98.320(b)(2) (2) Each degasification system well or shaft, 

including degasification systems deployed before, during, or after mining operations are conducted in a mine area. This includes both those wells and shafts where gas is emitted, and those where gas is sold, used onsite, or otherwise destroyed (including by flaring). 

(2) Each degasification system well or gob gas venhole, including degasification systems deployed before, during, or after mining operations are conducted in a mine area. This includes both those wells and vent holes where coal bed gas is emittedand those where the gas is sold, used onsite, or otherwise destroyed (including by flaring). 
50

Subpart Requirement Current Rule Text Proposed Rule Text 

FF 98.322(b) (b) You must report CH4 destruction from systems 

where gas is sold, used onsite, or otherwise destroyed (including by flaring). 

(b) You must report CH4 destruction from systems where gas is sold, used onsite, or otherwise destroyed (including by VAM oxidation and by flaring). 

FF 98.322(d) (d) You must report under this subpart the CO2

emissions from coal mine gas CH4 destruction 

occurring at the facility, where the gas is not a fuel input for energy generation or use ( e.g., flaring). 

(d) You must report under this subpart the CO2emissions from coal mine gas CH4 destruction 

occurring at the facility, where the gas is not a fuel input for energy generation or use ( e.g., flaring anVAM oxidation). 

FF 98.323(a) V = Volumetric flow rate for the quarter (cfm) based 

on sampling or a flow rate meter. If a flow rate meter is used and the meter automatically corrects for temperature and pressure, replace “520°R/T × P/1 atm” with “1”. 

V = Volumetric flow rate for the quarter (acfm) based on sampling or a flow rate meter. If a flow rameter is used and the meter automatically corrects standard temperature and pressure, then use scfm areplace “520°R/T × P/1 atm” with “1”. 

FF 98.323(a) MCF = Moisture correction factor for the 

measurement period, volumetric basis. = 1 when V and C are measured on a dry basis or if both are measured on a wet basis.= 1-(fH2O)n when V 

is measured on a wet basis and C is measured on a dry basis.= 1/[1-(fH2O)] when V is measured on a dry basis and C is measured on a wet basis. 

MCF = Moisture correction factor for the measurement period, volumetric basis. = 1 when V and C are measured on a dry basis or iboth are measured on a wet basis.= 1-(fH2O) when V is measured on a wet basis and C is measured on a dry basis.= 1/[1-(fH2O)] when V is measured on a dbasis and C is measured on a wet basis. 

FF 98.323(a) (fH2O) = Moisture content of the methane emitted 

during the measurement period, volumetric basis (cubic feet water per cubic feet emitted gas). 

(fH2O) = Moisture content of the methane emitted during the measurement period, volumetric basis (cubic feet water per cubic feet emitted gas). 

FF 98.323(a) P = Pressure at which flow is measured (atm) for the

quarter. The annual average barometric pressure from the nearest NOAA weather service station may be used as a default. 

P = Absolute pressure at which flow is measured (atm) for the quarter. The annual average barometrpressure from the nearest NOAA weather service station may be used as a default. 

FF 98.323(a)(2) (2) Values of V, C, T, P, and (fH2O), if applicable... (2) Values of V, C, T, P, and (fH2O), if applicable... FF 98.323(b) 

Equation FF3 

T Ti 

FF 98.323(b) Vi= Measured volumetric flow rate for the days in 

the week when the degasification system is in operation at that monitoring point, based on sampling or a flow rate meter (cfm). If a flow rate 

Vi= Measured volumetric flow rate for the days in the week when the degasification system is in operation at that monitoring point, based on sampling or a flow rate meter (acfm). If a flow rate 
51

Subpart Requirement Current Rule Text Proposed Rule Text 

meter is used and the meter automatically corrects for temperature and pressure, replace “520°R/Ti× Pi/1 atm” with “1”. 

meter is used and the meter automatically corrects standard temperature and pressure, then use scfm areplace “520°R/Ti× Pi/1 atm” with “1”. 

FF 98.323(b) fH2O fH2O FF 98.323(b) Pi = Pressure at which flow is measured (atm). Pi = Absolute pressure at which flow is measured 

(atm). 

FF 98.323(b)(1) (1) Values of V, C, T, P, and (fH2O), if applicable 

must be based on measurements taken at least once each quarter with no fewer than 6 weeks between measurements. If measurements are taken more frequently than once per quarter, then use the average value for all measurements taken. If continuous measurements are taken, then use the average value over the time period of continuous monitoring. 

(1) Values of V, C, T, P, and (fH2O), if applicable must be based on measurements taken at least once each quarter with no fewer than 6 weeks between measurements. If measurements are taken more frequently than once per quarter, then use the average value for all measurements taken. If continuous measurements are taken, then use the average value over the time period of continuous monitoring. 

FF 98.323(b)(2) CH4D (CH4D)i.j FF 98.323(c) (c) If gas from degasification system wells or 

ventilation shafts is sold, used onsite, or otherwise destroyed (including by flaring), you must calculate the quarterly CH4 destroyed for each destruction device and each point of offsite transport to a destruction device, using Equation FF–5 of this section. You must measure CH4 content and flow rate according to the provisions in §98.324, and calculate the methane routed to the destruction device (CH4) using either Equation FF–1 or Equation FF–3 of this section, as applicable. 

(c) If gas from a degasification system or ventilatiosystem is sold, used onsite, or otherwise destroyed (including by flaring or VAM oxidation), you muscalculate the quarterly CH4 destroyed for each destruction device and each point of offsite transpoto a destruction device, using Equation FF–5 of thisection. You must measure CH4 content and flow rate according to the provisions in §98.324, and calculate the methane routed to the destruction device (CH4) using either Equation FF–1 or EquatiFF–4 of this section, as applicable. 
52

Subpart Requirement Current Rule Text Proposed Rule Text 

FF 98.323 (c ) 

Equation FF6 

FF 98.324(b) (b) For CH4 liberated from ventilation systems, 

determine whether CH4 will be monitored from each 

ventilation well and shaft, from a centralized monitoring point, or from a combination of the two options. Operators are allowed flexibility for aggregating emissions from more than one ventilation well or shaft, as long as emissions from all are addressed, and the methodology for calculating total emissions documented. Monitor by one of the following options: 

(b) For CH4 liberated from ventilation systems, determine whether CH4 will be monitored from ea

ventilation shaft and vent hole, from a centralizedmonitoring point, or from a combination of the two options. Operators are allowed flexibility for aggregating emissions from more than one ventilation point, as long as emissions from all are addressed, and the methodology for calculating totemissions documented. Monitor by one of the following options: 

FF 98.324(c)(2) (2) Collect weekly (once each calendar week, with at 

least three days between measurements) or more frequent samples, for all degasification wells and gob gas vent holes. Determine weekly or more frequent flow rates, methane concentration, temperature, andpressure from these degasification wells and gob gas vent holes. Methane composition should be determined either by submitting samples to a lab for analysis, or from the use of methanometers at the degasification well site. Follow the sampling protocols for sampling of methane emissions from ventilation shafts, as described in §98.324(b)(1). You must record the date of sampling, flow, temperature, pressure, and moisture measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or 

(2) Collect weekly (once each calendar week, with least three days between measurements) or more frequent samples, for all degasification wells and ggas vent holes. Determine weekly or more frequenflow rates, methane concentration, temperature, anpressure from these degasification wells and gob gvent holes. Methane composition should be determined either by submitting samples to a lab foanalysis, or from the use of methanometers at the degasification monitoring site. Follow the samplinprotocols for sampling of methane emissions from ventilation shafts, as described in §98.324(b)(1). Ymust record the date of sampling, flow, temperaturpressure, and moisture measurements, the methane concentration (percent), the bottle number of sampcollected, and the location of the measurement or 
53

Subpart Requirement Current Rule Text Proposed Rule Text 

collection. collection.

FF 98.324(d)(2)(

iii) 

CCH4 CCH4 

FF 98.326(a) (a) Quarterly CH4 liberated from each ventilation 

monitoring point (CH4Vm), (metric tons CH4). 

(a) Quarterly CH4 liberated from each ventilation monitoring point, (metric tons CH4). 

FF 98.326(f) (f) Quarterly volumetric flow rate for each 

ventilation monitoring point (scfm), date and location of each measurement, and method of measurement (quarterly sampling or continuous monitoring), used in Equation FF–1 of this subpart. 

(f) Quarterly volumetric flow rate for each ventilation monitoring point and units of measure (scfm or acfm), date and location of each measurement, and method of measurement (quartesampling or continuous monitoring), used in Equation FF–1 of this subpart. 

FF 98.326(h) (h) Weekly volumetric flow rate used to calculate 

CH4 liberated from degasification systems (cfm) and method of measurement (sampling or continuous monitoring), used in Equation FF–3 of this subpart. 

(h) Weekly volumetric flow rate used to calculate CH4 liberated from degasification systems and uniof measure (acfm or scfm), and method of measurement (sampling or continuous monitoring)used in Equation FF–3 of this subpart. 

FF 98.326(i) (i) Quarterly CEMS CH4 concentration (%) used to 

calculate CH4 liberated from degasification systems (average from daily data), or quarterly CH4

concentration data based on results from weekly sampling data) (C). 

(i) Quarterly CH4 concentration (%) used to calculCH4 liberated from degasification systems and if thdata is based on CEMS or weekly sampling. 

FF 98.326(j) (j) Weekly volumetric flow rate used to calculate 

CH4 destruction for each destruction device and each point of offsite transport (cfm). 

(j) Weekly volumetric flow rate used to calculate CH4 destruction for each destruction device and eapoint of offsite transport, and units of measure (acfor scfm). 

FF 98.326(o) (o) Temperatures (°R), pressure (atm), and moisture 

content used in Equation FF–1 and FF–3 of this subpart, and the gaseous organic concentration correction factor, if Equation FF–9 was required. 

(o) Temperatures (°R), pressure (atm), moisture content, and the moisture correction factor (if applicable) used in Equation FF–1 and FF–3 of thisubpart; and the gaseous organic concentration correction factor, if Equation FF–9 was required. 

FF 98.326(r) (r) Identification information and description for 

each well and shaft, indication of whether the well orshaft is monitored individually, or as part of a centralized monitoring point. Note which method (sampling or continuous monitoring) was used. 

(r) Identification information and description for each well and shaft, including paragraphs (r)(1) through (r)(3) of this section: (1) Indication of whether the well or shaft is monitored individually, or as part of a centralized monitoring point. Note which method (sampling or 
54

Subpart Requirement Current Rule Text Proposed Rule Text 

continuous monitoring) was used.(2) Start date and close date of each well or shaft. (3) Number of days the well or shaft was in operation during the reporting year. 

FF 98.326(t) No current requirement (t) Quarterly CH4 routed to each destruction device 

or offsite transfer point used in Equation FF-5 of thsubpart (metric tons). 

FF 98.326(u) No current requirement (u) Mine Safety and Health Administration (MSHA

identification for this coal mine 

HH 98.343(a)(1) 

Equation HH1 

DOC = Degradable organic carbon from Table HH-1 of this subpart or measurement data, if available [fraction (metric tons C/metric ton waste)]. 

DOC = Degradable organic carbon from Table HHof this subpart [fraction (metric tons C/metric ton waste)]. 

HH Equation HH- 1, 98.345 F = Fraction by volume of CH4 in landfill gas from measurement data on a dry basis, if available 

(fraction); default is 0.5. 

F = Fraction by volume of CH4 in landfill gas from measurement data for the current reporting year, if available (fraction, dry basis, corrected to 0 percenoxygen); otherwise, use the default of 0.5. 

HH 98.343(b)(1) 

Equation HH4 

(C)n (CCH4)n 

HH 98.343(b)(1) 

Equation HH4 

N = Total number of measurement periods in a year. Use daily averaging periods for a continuous monitoring system and N=365 (or N = 366 for leap years). For weekly sampling, as provided in paragraph (b)(2) of this section, use N=52. 

N = Total number of measurement periods in a yeaUse daily averaging periods for a continuous monitoring system and N=365 (or N = 366 for leap years). For monthly sampling, as provided in paragraph (b)(2) of this section, use N=12. 

HH HH-4 0.0423 = Density of CH4 lb/cfm at 520°R or 60 

degrees Fahrenheit and 1 atm. 

0.0423 = Density of CH4 lb/cf at 520°R or 60 degrees Fahrenheit and 1 atm. 

HH 98.343(b)(2)(

i) 

(i) Continuously monitor gas flow rate and determine the cumulative volume of landfill gas each week and the cumulative volume of landfill gas each year that is collected and routed to a destruction device (before any treatment equipment). Under this option, the gas flow meter is not required to automatically correct for temperature, pressure, or, if necessary,moisture content. If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content, you mustdetermine these parameters as specified in paragraph (b)(2)(iii) of this section. 

(i) Continuously monitor gas flow rate and determithe cumulative volume of landfill gas each month and the cumulative volume of landfill gas each yeathat is collected and routed to a destruction device (before any treatment equipment). Under this optiothe gas flow meter is not required to automatically correct for temperature, pressure, or, if necessary,moisture content. If the gas flow meter is not equipped with automatic correction for temperaturpressure, or, if necessary, moisture content, you mudetermine these parameters as specified in paragra(b)(2)(iii) of this section. 
55

Subpart Requirement Current Rule Text Proposed Rule Text 

HH 98.343(b)(2)(

ii) 

(ii) Determine the CH4 concentration in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar week, there must be at least three days between measurements. 

(ii) Determine the CH4 concentration in the landfilgas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of thgas flow meter at least once each calendar month; only one measurement is made each calendar montthere must be at least fourteen days between measurements. 

HH 98.343(b)(2)(

iii)(A) 

(A) Determine the temperature and pressure in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar week, there must be at least three days between measurements. 

(A) Determine the temperature and pressure in the landfill gas that is collected and routed to a destruction device (before any treatment equipmenin a location near or representative of the location the gas flow meter at least once each calendar monif only one measurement is made each calendar month, there must be at least fourteen days betweemeasurements. 

HH 98.343(b)(2)(

iii)(B) 

(B) If the CH4 concentration is determined on a dry basis and flow is determined on a wet basis or CH4concentration is determined on a wet basis and flow is determined on a dry basis, and the flow meter does not automatically correct for moisture content, determine the moisture content in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar week, there must be at least three days between measurements. 

(B) If the CH4 concentration is determined on a dry basis and flow is determined on a wet basis or CH4concentration is determined on a wet basis and flow is determined on a dry basis, and the flow meter donot automatically correct for moisture content, determine the moisture content in the landfill gas tis collected and routed to a destruction device (before any treatment equipment) in a location neaor representative of the location of the gas flow meter at least once each calendar month; if only onmeasurement is made each calendar month, there must be at least fourteen days between measurements. 

HH 98.343(c )(1) 

(Eq. HH-5) 

OX = Oxidation fraction. Use the default value of 0.1 (10%). 

OX = Oxidation fraction. Use the appropriate oxidation fraction default value from Table HH-4 othis subpart. 

HH 98.343(c 

)(3)(i) (Eq. HH-6) 

HH 98.343(c (None) N = Number of landfill gas measurement locations 

( )

( ) ( ) Dest

CH

R DE f

G R

× − × − 14

∑ { } ( ) ( )

∑

=

=

× − ×

  − N

n

n n Dest n

N

n

CH n

R DE f

G R

1

,

1

1

4
56

Subpart Requirement Current Rule Text Proposed Rule Text 

)(3)(i)(Eq. HH-6) 

(associated with a destruction device or gas sent ofsite). If a single monitoring location is used to monitor volumetric flow and CH4 concentration of the recovered gas sent to one or multiple destructiodevices, then N=1. 

HH 98.343(c 

)(3)(i) (Eq. HH-6) 

R = Quantity of recovered CH4 from Equation HH-4 of this section (metric tons). 

Rn = Quantity of recovered CH4 from Equation HHof this section for the nth measurement location (metric tons). 

HH 98.343(c 

)(3)(i) (Eq. HH-6) 

OX = OX = Oxidation fraction. Use the default value of 0.1 (10%). 

OX = Oxidation fraction. Use the appropriate oxidation fraction default value from Table HH-4 othis subpart. 

HH 98.343(c 

)(3)(i) (Eq. HH-6) 

DE = Destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use DE = 1. 

DEn = Destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99) for the nth measurement location. If the gas itransported off-site for destruction, use DE = 1. If volumetric flow and CH4 concentration of the recovered gas is measured at a single location providing landfill gas to multiple destruction devic(including some gas destroyed on-site and some gasent off-site for destruction), calculate DEn as the 

arithmetic average of the DE values determined foeach destruction device associated with that measurement location. 

HH 98.343(c 

)(3)(i) (Eq. HH-6) 

fDest = Fraction of hours the destruction device was operating (annual operating hours / 8760 hours per year). If the gas is destroyed in a back-up flare (or similar device) or if the gas is transported off-site for destruction, use fDest = 1. 

fDest,n = Fraction of hours the destruction devicassociated with the nth measurement location was operating during active gas flow calculated as the annual operating hours for the destruction device divided by the annual hours flow was sent to the destruction device as measured at the nth measurement location. If the gas is destroyed in a back-up flare (or similar device) or if the gas is transported off-site for destruction, use fDest= 1. If tvolumetric flow and CH4 concentration of the recovered gas is measured at a single location providing landfill gas to multiple destruction devic(including some gas destroyed on-site and some gasent off-site for destruction), calculate fDest,n as the arithmetic average of the fDest values determined fo
57

Subpart Requirement Current Rule Text Proposed Rule Text 

each destruction device associated with that measurement

HH 98.343(c 

)(3)(ii) (Eq. HH-7) 

HH 98.343(c 

)(3)(ii) (Eq. HH-8) 

HH 98.343(c 

)(3)(ii) (Eq. HH-8) 

(None) N = Number of landfill gas measurement locations 

(associated with a destruction device or gas sent ofsite). If a single monitoring location is used to monitor volumetric flow and CH4 concentration of 

the recovered gas sent to one or multiple destructiodevices, then N=1. 

HH 98.343(c 

)(3)(ii) (Eq. HH-8) 

R = Quantity of recovered CH4 from Equation HH-4 of this section (metric tons CH4). 

Rn = Quantity of recovered CH4 from Equation HHof this section for the nth measurement location 

(metric tons CH4). 

HH 98.343(c 

)(3)(ii) (Eq. HH-8) 

fRec = Fraction of hours the recovery system was operating (annual operating hours/8760 hours per year). 

fRec,n = Fraction of hours the recovery system associated with the nth measurement location was 

operating (annual operating hours/8760 hours per year or annual operating hours / 8784 per year for leap year). 

HH 98.343(c 

)(3)(ii) (Eq. HH-8) 

OX = Oxidation fraction. Use the default value of 0.1 (10%). 

OX = Oxidation fraction. Use appropriate oxidatiofraction default value from Table HH-4 of this subpart. 

HH 98.343(c 

)(3)(ii) (Eq. HH-8) 

DE = Destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use DE = 1. 

DEn = Destruction efficiency (lesser of manufacturer's specified destruction efficiency and0.99) for the nth measurement location. If the gas is 

transported off-site for destruction, use DE = 1. If volumetric flow and CH4 concentration of the 

∑{ } ( ) ( )

∑ ∑

=

= =

× − ×

  −    

N

n

n n Dest n

N

n

n

N

n c n

n

R DE f

R

f

R

CE

1

,

1 Re , 1

1

1

(1 - OX) fR CE1 MG 1 Rec, n n ×   = ∑=Nn

( ) ( ) Dest

c

DE f

R

CE f

R − ×   − × 1 Re ∑{ } ( ) ( ) ∑ ∑

=

= =

× − ×

  −    

N

n

n n Dest n

N

n

n

N

n c n

n

R DE f

R

f

R

CE

1

,

1 Re , 1

1

1
58

Subpart Requirement Current Rule Text Proposed Rule Text 

recovered gas is measured at a single location providing landfill gas to multiple destruction devic(including some gas destroyed on-site and some gasent off-site for destruction), calculate DEn as the 

arithmetic average of the DE values determined foeach destruction device associated with that measurement location. 

HH 98.343(c)(3)(i

i) (Eq. HH-8) 

FDest, = Fraction of hours the destruction device was operating (device operating hours/8760 hours per year). If the gas is destroyed in a back-up flare (or similar device) or if the gas is transported off-site for destruction, use fDest= 1. 

fDest,n = Fraction of hours the destruction devicassociated with the nth measurement location was operating during active gas flow calculated as the annual operating hours for the destruction device divided by the annual hours flow was sent to the destruction device as measured at the nth measurement location. If the gas is destroyed in a back-up flare (or similar device) or if the gas is transported off-site for destruction, use fDest= 1. If tvolumetric flow and CH4 concentration of the recovered gas is measured at a single location providing landfill gas to multiple destruction devic(including some gas destroyed on-site and some gasent off-site for destruction), calculate fDest,n as the arithmetic average of the fDest values determined fo

each destruction device associated with that measurement location.

HH 98.344(e) (e) The owner or operator shall document the 

procedures used to ensure the accuracy of the estimates of disposal quantities and, if applicable, gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided. 

(e) For landfills electing to measure the fraction by volume of CH4 in landfill gas (F), follow the requirements in paragraphs (e)(1) and (e)(2) of this section. (1) Use a gas composition monitor capable of measuring the concentration of CH4 on a dry basis that is properly operated, calibrated, and maintaineaccording to the requirements specified in paragrap(b) of this section. You must either use a gas composition monitor that is also capable of measuring the O2 concentration correcting for exce(infiltration) air or you must operate, maintain, and 
59

Subpart Requirement Current Rule Text Proposed Rule Text 

calibrate a second monitor capable of measuring thO2 concentration on a dry basis according to the manufacturer's specifications. (2) Use Equation HH-10 of this section to correct tmeasured CH4 concentration to 0% oxygen. If multiple CH4 concentration measurements are madduring the reporting year, determine F separately feach measurement made during the reporting year, and use the results to determine the arithmetic average value of F for use in Equation HH–1 of thipart.  F = (CCH4/100%)x[20.9c/(20.9-%O2)] (Eq. HH10) Where: F = Fraction by volume of CH4 in landfill gas (fraction, dry basis, corrected to 0 percent oxygen)CCH4 = Measured CH4 concentration in landfill gas (volume percent, dry basis). 20.9c = Defined O2 correction basis, (volume percent, dry basis). 20.9 = O2 concentration in air (volume percent, dry basis). %O2 = Measured O2 concentration in landfill gas (volume percent, dry basis). 

HH 98.344(f) (None) (f) The owner or operator shall document the 

procedures used to ensure the accuracy of the estimates of disposal quantities and, if applicable, gas flow rate, gas composition, temperature, pressure, and moisture content measurements. Theprocedures include, but are not limited to, calibratiof weighing equipment, fuel flow meters, and othemeasurement devices. The estimated accuracy of measurements made with these devices shall also brecorded, and the technical basis for these estimateshall be provided. 

HH 98.345(c) (c) For missing daily waste disposal quantity data for 

disposal in reporting years, the substitute value 

(c) For missing daily waste disposal quantity data fdisposal in the reporting year, the substitute value 
60

Subpart Requirement Current Rule Text Proposed Rule Text 

shall be the average daily waste disposal quantity for that day of the week as measured on the week before and week after the missing daily data. 

shall be the average daily waste disposal quantity fthat day of the week as measured on the week befoand week after the missing daily data. 

HH 98.346(d)(1) (1) Degradable organic carbon (DOC), methane 

correction factor (MCF), and fraction of DOC dissimilated (DOCF) values used in the calculations. If an MCF value other than the default of 1 is used, provide an indication of whether active aeration of the waste in the landfill was conducted during the reporting year, a description of the aeration system, including aeration blower capacity, the fraction of the landfill containing waste affected by the aeration, the total number of hours during the year the aeration blower was operated, and other factors used as a basis for the selected MCF value. 

(1) Degradable organic carbon (DOC) and fraction DOC dissimilated (DOCF) values used in the calculations. 

HH 98.346(e) (e) Fraction of CH4in landfill gas (F), and an 

indication of whether the fraction of CH4was 

determined based on measured values or the default value 

(e) Fraction of CH4 in landfill gas (F), an indication of whether the fraction of CH4 was determined bason measured values or the default value, and the methane correction factor (MCF) used in the calculations. If an MCF other than the default of 1 used, provide an indication of whether active aeration of the waste in the landfill was conducted during the reporting year, a description of the aeration system, including aeration blower capacitythe fraction of the landfill containing waste affecteby aeration, the total number of hours during the ythe aeration blower was operated, and other factors used as a basis for the selected MCF value. 
61

Subpart Requirement Current Rule Text Proposed Rule Text 

HH 98.346(h) (h) For landfills without gas collection systems, the 

annual methane emissions (i.e., the methane generation, adjusted for oxidation, calculated using Equation HH–5 of this subpart), reported in metric tons CH4, and an indication of whether passive vents and/or passive flares (vents or flares that arenot considered part of the gas collection system as defined in §98.6) are present at this landfill. 

(h) For landfills without gas collection systems, thannual methane emissions (i.e., the methane generation, adjusted for oxidation, calculated using Equation HH–5 of this subpart), reported in metric tons CH4, the oxidation fraction used in the calculation, and an indication of whether passive vents and/or passive flares (vents or flares that arenot considered part of the gas collection system as defined in §98.6) are present at this landfill. 

HH 98.346(i)(5) (5) An indication of whether destruction occurs at 

the landfill facility or offsite. If destruction occurs at the landfill facility, also report an indication of whether a back-up destruction device is present at the landfill, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), and the destruction efficiency used (percent). 

(5) An indication of whether destruction occurs at the landfill facility, off-site, or both. If destruction occurs at the landfill facility, also report for each measurement location an indication of whether a back-up destruction device is present at the landfillthe annual operating hours for the primary destruction device, the annual operating hours for tback-up destruction device (if present), and the destruction efficiency used (percent). 

HH 98.346(i)(8) (8) Methane generation corrected for oxidation 

calculated using Equation HH-5 of this subpart, reported in metric tons CH4. 

(8) Methane generation corrected for oxidation calculated using Equation HH-5 of this subpart, reported in metric tons CH4, and the oxidation fraction used in the calculation 

HH 98.346(i)(10) (8) Methane generation corrected for oxidation 

calculated using Equation HH-7 of this subpart, reported in metric tons CH4. 

(8) Methane generation corrected for oxidation calculated using Equation HH-7 of this subpart, reported in metric tons CH4, and the oxidation fraction used in the calculation 

HH 98.346(i)(11) (8) Methane generation corrected for oxidation 

calculated using Equation HH-6 of this subpart, reported in metric tons CH4. 

(8) Methane generation corrected for oxidation calculated using Equation HH-6 of this subpart, reported in metric tons CH4, and the oxidation fraction used in the calculation 

HH 98.346(i)(12) (8) Methane generation corrected for oxidation 

calculated using Equation HH-8 of this subpart, reported in metric tons CH4. 

(8) Methane generation corrected for oxidation calculated using Equation HH-8 of this subpart, reported in metric tons CH4, and the oxidation fraction used in the calculation 
62

Subpart Requirement Current Rule Text Proposed Rule Text 

HH 98.348 (None) Landfill capacity means the maximum amount of 

solid waste a landfill can accept. For the purposes this subpart, for landfills that have a permit, the landfill capacity can be determined in terms of volume or mass in the most recent permit issued by the state, local, or Tribal agency responsible for regulating the landfill, plus any in-place waste not accounted for in the most recent permit. If the ownor operator chooses to convert from volume to masto determine its capacity, the calculation must include a site-specific density. 

HH 98.348 (None) Leachate recirculation means the practice of takin

the leachate collected from the landfill and reapplying it to the landfill by any of one of a varieof methods, including pre-wetting of the waste, direct discharge into the working face, spraying, infiltration ponds, vertical injection wells, horizontgravity distribution systems, and pressure distribution systems. 

HH Table HH-2 Table HH-2 See Appendix A for changes to Table HH-2 HH Table HH-4 None See Appendix A for Table HH-4 

II 98.353(d)(2) - Eq. II-6 fDest_1 = Fraction of hours the primary destruction device was operating (device operating hours/hours 

in the year). If the biogas is transported off-site for destruction, use fDest = 1. 

fDest_1 = Fraction of hours the primary destruction device was operating calculated as the annual hourwhen the destruction device was operating divided by the annual operating hours of the biogas recovesystem. If the biogas is transported off-site for destruction, use fDest = 1. 

II 98.353(d)(2) - Eq. II-6 fDest_2 = Fraction of hours the back-up destruction device was operating (device operating hours/hours 

in the year). 

fDest_2 = Fraction of hours the back-up destruction device was operating calculated as the annual hourwhen the destruction device was operating divided by the annual operating hours of the biogas recovesystem. 

LL 98.386(a)(1) (1) For each product listed in Table MM-1 of subpart 

MM of this part that enters the coal-to-liquid facility to be further processed or otherwise used on site, report the annual quantity in metric tons or barrels by 

(1) [Reserved.] 
63

Subpart Requirement Current Rule Text Proposed Rule Text 

each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. 

LL 98.386(a)(4) (4) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph (a)(1) of this section. 

(4) Each standard method or other industry standarpractice used to measure each quantity reported in paragraph (a)(2) of this section. 

LL 98.386(a)(5) (5) For each product (leaving the coal-to-liquid 

facility) listed in Table MM-1 of subpart MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. Those products that enter the facility, but are not reported in (a)(1), shall not be reported under this paragraph. 

(5) [Reserved.] 

LL 98.386(a)(8) (8) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph (a)(5) of this section. 

(8) Each standard method or other industry standarpractice used to measure each quantity reported in paragraph (a)(6) of this section. 

LL 98.386(a)(9)(

v) 

(v) The calculated CO2 emissions factor. (v) The calculated CO2 emissions factor in metric 

tons CO2 per barrel or per metric ton of product. 

LL 98.386(a)(11)

(v) 

(v) The calculated CO2 emissions factor. (v) The calculated CO2 emissions factor in metric 

tons CO2 per barrel or per metric ton of product. 

LL 98.386(a)(13) (13)For each specific type of biomass that enters the 

coal-to-liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. 

(13) [Reserved.] 

LL 98.386(a)(15) (15) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph (a)(3) of this section. 

(15) Each standard method or other industry standapractice used to measure each quantity reported in paragraph (a)(14 ) of this section. 

LL 98.386(a)(18) (18) Annual CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each type of biomass feedstock co-processed with fossil fuel-based feedstocks reported in paragraph (a)(3) of this section, calculated according to §98.393(c). 

(18) Annual CO2 emissions in metric tons that wouresult from the complete combustion or oxidation oeach type of biomass feedstock co-processed with fossil fuel-based feedstocks reported in paragraph (a)(14) of this section, calculated according to §98.393(c). 
64

Subpart Requirement Current Rule Text Proposed Rule Text 

LL 98.386(b)(1) (1) For each product listed in Table MM-1 of subpart 

MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. 

1) [Reserved.] 

LL 98.386(b)(4) (4) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph (b)(1) of this section. 

(4) Each standard method or other industry standarpractice used to measure each quantity reported in paragraph (b)(2) of this section. 

LL 98.386(b)(5)(

v) 

(v) The calculated CO2 emissions factor in metric tons. 

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product. 

LL 98.386( c)(1) (1) For each product listed in Table MM-1 of subpart 

MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. 

(1) [Reserved.] 

LL 98.386( c)(4) (4) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph (c)(1) of this section 

(4) Each standard method or other industry standarpractice used to measure each quantity reported in paragraph (c)(2) of this section 

LL 98.386( 

c)(5)(v) 

(v) The calculated CO2 emissions factor in metric tons. 

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product. 

LL 98.386(d)(2) (2) For a product that enters the facility to be further 

refined or otherwise used on site that is a blended feedstock, producers must meet the reporting requirements of paragraphs (a)(1) and (a)(2) of this section by reflecting the individual components of the blended feedstock. 

(2) For a product that enters the facility to be furthrefined or otherwise used on site that is a blended feedstock, producers must meet the reporting requirements of paragraph (a)(2) of this section by reflecting the individual components of the blendefeedstock. 

LL 98.386(d)(3) (3) For a product that is produced, imported, or 

exported that is a blended product, producers, importers, and exporters must meet the reporting requirements of paragraphs (a)(5), (a)(6), (b)(1), (b)(2), (c)(1), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product. 

(3) For a product that is produced, imported, orexported that is a blended product, producers, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2of this section, as applicable, by reflecting the individual components of the blended product. 

MM 98.393(a)(1) Producti = Annual volume of product "i" produced, 

imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate, and excludes products that 

Producti = Annual volume of product "i" producedimported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate, and excludes products th
65

Subpart Requirement Current Rule Text Proposed Rule Text 

entered the refinery but are not reported under 98.396(a)(1). For natural gas liquids, volumes shall reflect the individual components of the product as listed in Table MM-1 to subpart MM. 

entered the refinery but are not reported under 98.396(a)(2). For natural gas liquids, volumes shareflect the individual components of the product as listed in Table MM-1 to subpart MM. 

MM 98.393(a)(2) Producti = Annual mass of product "i" produced, 

imported, or exported by the reporting party (metric tons). For refiners, this mass only includes products ex refinery gate. 

Producti = Annual mass of product "i" produced, imported, or exported by the reporting party (metritons). For refiners, this mass only includes productex refinery gate, and excludes products that entered the refinery but are not reported under §98.396(a)(

MM 98.393(h)(1) (1) A reporter using Calculation Methodology 1 to 

determine the emission factor of a petroleum product shall calculate the CO2 emissions associated with that product using Equation MM–8 of this section in place of Equation MM–1 of this section. 

(1) A reporter using Calculation Method 1 todetermine the emission factor of a petroleum produshall calculate the CO2 emissions associated with that product using Equation MM–8 of this section place of Equation MM–1 of this section. 

MM 98.393(h)(2) A refinery using Calculation Methodology 1 of this 

subpart to determine the emission factor of a noncrude petroleum feedstock shall calculate the CO2emissions associated with that feedstock using Equation MM–9 of this section in place of Equation MM–2 of this section. 

(2) A refinery using Calculation Method 1 of this subpart to determine the emission factor of a noncrude petroleum feedstock shall calculate the CO2emissions associated with that feedstock using Equation MM–9 of this section in place of EquatioMM–2 of this section. 

MM 98.394(a)(1) (1) The quantity of petroleum products, natural gas 

liquids, and biomass, as well as the quantity of crude oil measured on site at a refinery, shall be determined as follows: 

(1) The quantity of petroleum products, natural gas liquids, and biomass, shall be determined as follow

MM 98.394(a)(3) (3) The quantity of crude oil not measured on site at 

a refinery shall be determined according to one of thefollowing methods. You may use an appropriate standard method published by a consensus-based standards organization or you may use an industry standard practice. 

(3) The annual quantity of crude oil received shall determined according to one of the following methods. You may use an appropriate standard method published by a consensus-based standards organization or you may use an industry standard practice. 
66

Subpart Requirement Current Rule Text Proposed Rule Text 

MM 98.394(b) (None) (3) For units and processes that operate continuous

with infrequent outages, it may not be possible to complete the calibration of a flow meter or other measurement device without disrupting normal process operation. In such cases, the owner or operator may postpone the calibration until the nexscheduled maintenance outage. The best available information from company records may be used in the interim. Such postponements shall be documented in the monitoring plan that is required under §98.3(g)(5). 

MM 98.394(c) (c) Procedures for Calculation Methodology 2 of this 

subpart. 

(c) Procedures for Calculation Method 2 of this subpart. 

MM 98.394(d) (d) Measurement of API gravity and sulfur content 

of crude oil 

(4) [Reserved] 

MM 98.395(a)

(a) Determination of quantity. Whenever the quality 

assurance procedures in §98.394(a) cannot be followed to measure the quantity of one or more petroleum products, natural gas liquids, types of biomass, feedstocks, or crude oil batches during any period (e.g., if a meter malfunctions), the following missing data procedures shall be used: 

(a) Determination of quantity. Whenever the qualitassurance procedures in §98.394(a) cannot be followed to measure the quantity of one or more petroleum products, natural gas liquids, types of biomass, feedstocks, or crude oil during any period (e.g., if a meter malfunctions), the following missindata procedures shall be used: 

MM 98.395(b) (b) Determination of emission factor. Whenever any 

of the procedures in §98.394(c) cannot be followed to develop an emission factor for any reason, Calculation Methodology 1 of this subpart must be used in place of Calculation Methodology 2 of this subpart for the entire reporting year. 

(b) Determination of emission factor. Whenever anof the procedures in §98.394(c) cannot be followed to develop an emission factor for any reason, Calculation Method 1 of this subpart must be used place of Calculation Method 2 of this subpart for thentire reporting year. 

MM 98.395(c ) (c) Determination of API gravity and sulfur content 

of crude oil. For missing data on sulfur content or 

(c ) [Reserved] 
67

Subpart Requirement Current Rule Text Proposed Rule Text 

API gravity, the substitute data value shall be thearithmetic average of the quality-assured values of API gravity or sulfur content in the batch preceding and the batch immediately following the missing data incident. If no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured values for API gravity and sulfur content obtained from the batch after the missing data period. 

MM 98.396(a)(1) (1) For each petroleum product or natural gas liquid 

listed in table MM–1 of this subpart that enters the refinery to be further refined or otherwise used on site, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. 

(1) [Reserved] 

MM 98.396(a)(4) (4) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph (a)(1) of this section. 

(4) Each standard method or other industry standarpractice used to measure each quantity reported in paragraph (a)(2) of this section. 

MM 98.396(a)(5) (5) For each petroleum product and natural gas liquid 

(ex refinery gate) listed in Table MM–1 of this subpart, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. Petroleum products and natural gas liquids that enter the refinery, but are not reported in (a)(1), shall not be reported under this paragraph. 

(5) [Reserved] 

MM 98.396(a)(8) (8) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph (a)(5) of this section. 

(8) Each standard method or other industry standarpractice used to measure each quantity reported in paragraph (a)(6) of this section. 

MM 98.396(a)(9) (9) For every feedstock reported in paragraph (a)(2) 

of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report: 

(9) For every feedstock reported in paragraph (a)(2of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report: 

MM 98.396(a)(9)(i (iii) The carbon share test results in percentmass (iii) The carbon share test results in percent mass 
68

Subpart Requirement Current Rule Text Proposed Rule Text 

ii)

MM 98.396(a)(9)(

v) 

(v) The calculated CO2 emissions factor in metric tons. 

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product. 

MM 98.396(a)(10) (10) For every non-solid feedstock reported in 

paragraph (a)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report: 

(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which CalculatiMethod 2 of this subpart was used to determine an emissions factor, report: 

MM 98.396(a)(11) (11) For every petroleum product and natural gas 

liquid reported in paragraph (a)(6) of this section for which Calculation Methodology2 of this subpart was used to determine an emissions factor, report: 

(11) For every petroleum product and natural gas liquid reported in paragraph (a)(6) of this section fwhich Calculation Method 2 of this subpart was usto determine an emissions factor, report: 

MM 98.396(11)(iii

) 

(iii) The carbon share test results in percentmass. (iii) The carbon share test results in percent mass. 

MM 98.396(a)(13) (13) For each specific type of biomass that enters the 

refinery to be co-processed with petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. 

(13) [Reserved] 

MM 98.396(a)(15) (15) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph (a)(13) of this section. 

(15) Each standard method or other industry standapractice used to measure each quantity reported in paragraph (a)(14) of this section. 

MM 98.396(a)(18) (18) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of each type of biomass feedstock co-processed with petroleum feedstocks reported in paragraph (a)(13) of this section, calculated according to §98.393(c). 

(18) The CO2 emissions in metric tons that would result from the complete combustion or oxidation oeach type of biomass feedstock co-processed with petroleum feedstocks reported in paragraph (a)(14) of this section, calculated according to §98.393(c). 

MM 98.396(a)(20) (20) All of the following information for all crude oil 

feedstocks used at the refinery: (i) Batch volume in barrels. (ii) Weighted average API gravity representing the batch at the point of entry at the refinery. (iii) Weighted average sulfur content representing the batch at the point of entry at the refinery. (iv) Country of origin, of the batch, if known and data in paragraphs (a)(20)(v) and (a)(20)(vi) of this section are unknown. 

(20) For all crude oil that enters the refinery, reporthe annual quantity in barrels. 
69

Subpart Requirement Current Rule Text Proposed Rule Text 

(v) EIA crude stream code and crude stream name of the batch, if known. (vi) Generic name for the crude stream and the appropriate EIA two-letter country or state and production area code of the batch, if known and no appropriate EIA crude stream code exists. 

MM 98.396(a)(21) (21) The quantity of bulk NGLs in metric tons or 

barrels received for processing during the reporting year. 

(21) The quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. Report only quantities of bulk NGLs not reported in (a)(2) of this section. 

MM 98.396(a)(22) (22) Volume of crude oil in barrels that you injected 

into a crude oil supply or reservoir. A volume of crude oil that entered the refinery, but was not reported in paragraphs (a)(2) or (a)(20), shall not be reported under this paragraph. 

(22) Volume of crude oil in barrels that you injecteinto a crude oil supply or reservoir. 

MM 98.396(a)(23) (23) Special provisions for 2010. For reporting year 

2010 only, a refiner that knows the information under a specific tier of the batch definition in 40 CFR 98.398, but does not have the necessary data collection and management in place to readily report this information, can use the next most appropriate tier of the batch definition for reporting batch information under paragraph 98.396(a)(20). 

(23) [Reserved] 

MM 98.396(b)(1) (1) For each petroleum product and natural gas liquid 

listed in Table MM–1 of this subpart, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. 

(1) [Reserved] 

MM 98.396(b)(2) (2) For each petroleum product and natural gas liquid 

listed in Table MM–1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product as listed in Table MM–1 of this subpart. 

(2) For each petroleum product and natural gas liqulisted in Table MM–1 of this subpart, report the annual quantity in metric tons or barrels. For naturgas liquids, quantity shall reflect the individual components of the product. 
70

Subpart Requirement Current Rule Text Proposed Rule Text 

MM 98.396(b)(4) (4) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph (b)(1) of this section. 

(4) Each standard method or other industry standarpractice used to measure each quantity reported in paragraph (b)(2) of this section. 

MM 98.396(b)(5) (5) For each product reported in paragraph (b)(2) of 

this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report: 

(5) For each product reported in paragraph (b)(2) othis section for which Calculation Method 2 of this subpart used was used to determine an emissions factor, report: 

MM 98.396(b)(6) (6) For each non-solid product reported in paragraph 

(b)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report: 

(6) For each non-solid product reported in paragrap(b)(2) of this section for which Calculation Method of this subpart was used to determine an emissions factor, report: 

MM 98.396( c)(1) (1) For each petroleum product and natural gas liquid 

listed in Table MM–1 of this subpart, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. 

(1)[Reserved] 

MM 98.396( c)(4) (4) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph (c)(1) of this section. 

(4) Each standard method or other industry standarpractice used to measure each quantity reported in paragraph (c)(2) of this section. 

MM 98.396(c)(5) (5) For each product reported in paragraph (c)(2) of 

this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report: 

(5) For each product reported in paragraph (c)(2) othis section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report: 

MM 98.396(c)(6) (6) For each non-solid product reported in paragraph 

(c)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report: 

(6) For each non-solid product reported in paragrap(c)(2) of this section for which Calculation Method of this subpart used was used to determine an emissions factor, report: 

MM 98.396(d)(2) (2) For a product that enters the refinery to be further 

refined or otherwise used on site that is a blended non-crude feedstock, refiners must meet the reporting requirements of paragraphs (a)(1) and (a)(2) of this section by reflecting the individual components of the blended non-crude feedstock. 

(2) For a product that enters the refinery to be furthrefined or otherwise used on site that is a blended non-crude feedstock, refiners must meet the reporting requirements of paragraphs (a)(2) of this section by reflecting the individual components of the blended non-crude feedstock. 

MM 98.396(d)(3) (3) For a product that is produced, imported, or (3) For a product that is produced, imported, or 
71

Subpart Requirement Current Rule Text Proposed Rule Text 

exported that is a blended product, refiners, importers, and exporters must meet the reporting requirements of paragraphs (a)(5), (a)(6), (b)(1), (b)(2), (c)(1), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product. 

exported that is a blended product, refiners, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2of this section, as applicable, by reflecting the individual components of the blended product. 

MM 98.397(b) (b) Reporters shall maintain records to support 

quantities that are reported under this subpart, including records documenting any estimations of missing data and the number of calendar days in the reporting year for which substitute data procedures were followed. For all reported quantities of petroleum products, natural gas liquids, and biomass, as well as crude oil quantities measured on site at a refinery, reporters shall maintain metering, gauging, and other records normally maintained in the course of business to document product and feedstock flows including the date of initial calibration and the frequency of recalibration for the measurement equipment used. 

(b) Reporters shall maintain records to support quantities that are reported under this subpart, including records documenting any estimations of missing data and the number of calendar days in threporting year for which substitute data procedures were followed. For all reported quantities of petroleum products, natural gas liquids, and biomareporters shall maintain metering, gauging, and othrecords normally maintained in the course of business to document product and feedstock flows including the date of initial calibration and the frequency of recalibration for the measurement equipment used. 

MM 98.397(d) (d) Reporters shall maintain laboratory reports,

calculations and worksheets used in the measurement of density and carbon share for any petroleum product or natural gas liquid for which CO2 emissions were calculated using Calculation Methodology 2. 

(d) Reporters shall maintain laboratory reports, calculations and worksheets used in the measuremof density and carbon share for any petroleum product or natural gas liquid for which CO2 emissions were calculated using Calculation Metho2. 

MM 98.398 (None) Bulk NGLs for purposes of reporting under this 

subpart means mixtures of NGLs that are sold or delivered as undifferentiated product. 

MM 98.398 (None) Natural Gas Liquids (NGLs) for the purposes of 

reporting under this subpart means hydrocarbons thare separated from natural gas as liquids through thprocess of absorption, condensation, adsorption, or other methods, and are sold or delivered as differentiated product. Generally, such liquids consist of ethane, propane, butanes, or pentanes plu
72

Subpart Requirement Current Rule Text Proposed Rule Text 

MM 98.398 Batch means either a volume of crude oil that enters 

a refinery or the components of such volume (e.g., the volumes of different crude streams that are blended together and then delivered to a refinery). The batch volume is the first appropriate tier in the following list: (1) Up to an annual volume of a type of crude oil identified by an EIA crude stream code, if the EIA crude stream code is known. (2) Up to an annual volume of a type of crude oil identified by a generic name for the crude stream and an appropriate EIA two-letter country or state and production area code, if the generic name and EIA two-letter code are known but no appropriate EIA crude stream code exists. (3) Up to a calendar month of crude oil volume from a single known foreign country of origin if the crude stream name is unknown. (4) Up to a calendar month of crude oil volume from the United States if the crude stream name and production area are unknown. (5) Up to a calendar month of crude oil volume if the country of origin is unknown. 

(None)

MM Table MM-1 Table MM-1 See Appendix A for changes to Table MM-1 

NN 98.400(a) (a) Natural gas liquids fractionators are installations 

that fractionate natural gas liquids (NGLs) into their consitutent liquid products (ethane, propane, normal butane, isobutane or pentanes plus) for supply to downstream facilities. 

(a) Natural gas liquids fractionators are installationthat fractionate natural gas liquids (NGLs) into theconstituent liquid products or mixtures of products (ethane, propane, normal butane, isobutane or pentanes plus) for supply to downstream facilities. 

NN 98.400(b) (b) Local Distribution Companies (LDCs) are 

companies that own or operate distribution pipelines, not interstate pipelines or intrastate pipelines, thatphysically deliver natural gas to end users and that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution systems. 

(b) Local Distribution Companies (LDCs) are companies that own or operate distribution pipelinnot interstate pipelines or intrastate pipelines, thatphysically deliver natural gas to end users and that are within a single state that are regulated as separaoperating companies by State public utility commissions or that operate as independent municipally-owned distribution systems. LDCs do not include pipelines (both interstate and intrastatedelivering natural gas directly to major industrial 
73

Subpart Requirement Current Rule Text Proposed Rule Text 

users and farm taps upstream of the local distributicompany inlet. 

NN 98.403(a)(2) Fuelh = Total annual volume of product “h” supplied 

(bbl or Mscf per year) 

Fuelh = Total annual volume of product “h” suppli(volume per year, in Mscf for natural gas and bbl fNGLs). 

NN 98.403(b) (1) (1) For natural gas that is received for redelivery to 

downstream gas transmission pipelines and other local distribution companies, use eEquation NN–3 of this section and the default values for the CO2emission factors found in Table NN–2 of this subpart.*** 

(1) For natural gas that is received for redelivery to downstream gas transmission pipelines and other local distribution companies, use Equation NN–3 othis section and the default values for the CO2 emission factors found in Table NN–2 of this subpart.***. 

NN 98.403(b)(2)(

i) 

(2)(i) For natural gas delivered to each meter registering a supply equal to or greater than 460,000 Mscf per year, use Equation NN–4 of this section and the default values for the CO2 emission factors 

found in Table NN–2 of this subpart. 

(2)(i) For natural gas delivered to end-users registering a supply equal to or greater than 460,00Mscf per year, use Equation NN–4 of this section and the default values for the CO2 emission factors 

found in Table NN–2 of this subpart. 

NN 98.403(b)(2)(

ii) 

CO2k = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas received by end-users that receive a supply equal to or greater than 460,000 Mscf per year (metric tons). 

CO2k = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas delivered to each end-user that receives a suppequal to or greater than 460,000 Mscf per year (metric tons). 

NN 98.403(b)(2)(

ii) 

Fuel = Total annual volume of natural gas supplied (Mscf per year). 

Fuel = Total annual volume of natural gas supplied to this end-user, if known, otherwise, the annual volume supplied to this meter (Mscf per year). 

NN 98.403(b)(3) (3) For natural gas received by the LDC at the city 

gate that is injected into on-system storage, and/or liquefied and stored, use Equation NN–5 of this section and the default value for the CO2 emission factors found in Table NN–2 of this subpart. Alternatively, a reporter-specific CO2 emission 

factor may be used, provided it is developed using methods outlined in §98.404. CO2l = [Fuel1-Fuel2]*EF (Eq. NN-5) Where: CO2l = Annual CO2 mass emissions that would result from the combustion or oxidation of the net natural gas that is liquefied and/or stored and not used for 

(3) For the net change in natural gas stored on system by the LDC during the reporting year, use Equation NN-5a of this section. For natural gas thais received by means other than through the city gaand is not otherwise accounted for by Equation NNor NN-2 of this section, use Equation NN-5b of thisection. (i) For natural gas received by the LDC that is injected into on-system storage, and/or liquefied anstored, and for gas removed from storage and used for deliveries, use Equation NN–5a of this section and the default value for the CO2 emission factors 

found in Table NN–2 of this subpart. Alternatively
74

Subpart Requirement Current Rule Text Proposed Rule Text 

deliveries by the LDC within the reported year (metric tons). Fuel1 = Total annual volume of natural gas received by the LDC at the city gate and stored on-system or liquefied and stored in the reporting year (Mscf per year). Fuel2 = Total annual volume of natural gas that is used for deliveries in the reporting year that was not otherwise accounted for in Equation NN–1 or NN–2 of this section (Mscf per year). This primarily includes natural gas previously stored on-system or liquefied and stored that is removed from storage and used for deliveries to customers or other LDCs by the LDC within the reporting year. This also includes natural gas that bypassed the city gate and was delivered directly to LDC systems from producers or natural gas processing plants from local production. EF = Fuel-specific CO2 emission factor (MT CO2/Mscf). 

reporter-specific CO2 emission factor may be usedprovided it is developed using methods outlined in §98.404. CO2l = [Fuel1-Fuel2]*EF (Eq. NN-5a) Where: CO2l = Annual CO2 mass emissions that would res

from the combustion or oxidation of the net changin natural gas stored on system by the LDC within the reporting year (metric tons). Fuel1 = Total annual volume of natural gas added tstorage on-system or liquefied and stored in the reporting year (Mscf per year). Fuel2 = Total annual volume of natural gas that is removed from storage or vaporized and removed from storage and used for deliveries to customers oother LDCs by the LDC within the reporting year (Mscf per year). EF = Annual average CO2 emission factor for natugas placed into/removed from storage(MT CO2/Mscf). 

NN 98.403(b)(3)(

ii) 

(None) (ii)(ii) For natural gas received by the LDC that 

bypassed the city gate, use Equation NN-5b of this section. This includes natural gas received directly by LDC systems from producers or natural gas processing plants from local production, received aa liquid and vaporized for delivery, or received froany other source that bypassed the city gate. Use thdefault value for the CO2 emission factors found in Table NN–2 of this subpart. Alternatively, a reportspecific CO2 emission factor may be used, provideit is developed using methods outlined in §98.404. CO2n = Fuelz * EFz Where: CO2n = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas received that bypassed the city gate and is not otherwise accounted for by Equation NN-1 or NN-of this section (metric tons). Fuelz = Total annual volume of natural gas receive
75

Subpart Requirement Current Rule Text Proposed Rule Text 

that was not otherwise accounted for by Equation NN-1 or NN-2 of this section (natural gas from producers and natural gas processing plants from local production, or natural gas that was received aa liquid, vaporized and delivered, and any other source that bypassed the city gate) (Mscf per year)EFz = Fuel-specific CO2 emission factor (MT CO2/Mscf). 

NN 98.403(b)(4) (4) Calculate the total CO2 emissions that would 

result from the complete combustion or oxidation of the annual supply of natural gas to end-users using Equation NN–6 of this section. CO2 = Sum(CO2i)-Sum(CO2j)-Sum(CO2k)-Sum(CO2l) Where: CO2 = Annual CO2 mass emissions that would result 

from the combustion or oxidation of natural gas delivered to LDC customers not covered in paragraph (b)(2) of this section (metric tons). CO2i =Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas delivered to transmission pipelines or other LDCs as calculated in paragraph (b)(1) of this section (metric tons). CO2j = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas delivered to transmission pipelines or other LDCs as calculated in paragraph (b)(1) of this section (metric tons). CO2k = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas received by end-users that receive a supply equal to or greater than 460,000 Mscf per year as calculated in paragraph (b)(2) of this section (metric tons). CO2l = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas received by the LDC and liquefied and/or stored but not used for deliveries within the reported year as 

(4) Calculate the total CO2 emissions that would result from the complete combustion or oxidation othe annual supply of natural gas to end-users that receive a supply less than 460,000 Mscf per year using Equation NN–6 of this section. CO2 = CO2i+CO2n-CO2j-∑CO2k-CO2l (Eq. NN-6) Where CO2 = Annual CO2 mass emissions that would resufrom the combustion or oxidation of natural gas delivered to LDC end-users not covered in paragra(b)(2) of this section (metric tons). CO2i = Annual CO2 mass emissions that would resfrom the combustion or oxidation of natural gas received at the city gate as calculated in paragraph (a)(1) or (a)(2) of this section (metric tons). CO2j = Annual CO2 mass emissions that would res

from the combustion or oxidation of natural gas delivered to transmission pipelines or other LDCs calculated in paragraph (b)(1) of this section (metrtons). CO2k = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas delivered to each end-user that receives a suppequal to or greater than 460,000 Mscf per year as calculated in paragraph (b)(2) of this section (metrtons). CO2l = Annual CO2 mass emissions that would resfrom the combustion or oxidation of the net changin natural gas stored by the LDC within the reporteyear as calculated in paragraph (b)(3)(i) of this section (metric tons). 
76

Subpart Requirement Current Rule Text Proposed Rule Text 

calculated in paragraph (b)(3) of this section (metric tons). 

CO2n = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas that was received by the LDC directly from sources bypassing the city gate, and is not otherwiaccounted for in Equation NN-1 or NN-2 of this section, as calculated in paragraph (b)(3)(ii) of this section (metric tons). 

NN 98.403( c)(2) (2) Calculate the total CO2 equivalent emissions that 

would result from the combustion or oxidation of fractionated NGLs supplied less the quantity received by other fractionators using Equation NN-8 of this section. 

(2) Calculate the total CO2 equivalent emissions thwould result from the combustion or oxidation of fractionated NGLs supplied less the quantity received from other fractionators using Equation NN-8 of this section. 

NN 98.403( c)(2) CO2 = Annual CO2 mass emissions that would result 

from the combustion or oxidation of fractionated NGLs delivered to customers or on behalf of customers (metric tons). 

CO2 = Annual CO2 mass emissions that would resufrom the combustion or oxidation of fractionated NGLs delivered to customers or on behalf of customers less the quantity received from other fractionators (metric tons). 

NN 98.404(a)(5) (5) For an LDC using Equation NN–1 or NN–2 of 

this subpart, the point(s) of measurement for the natural gas volume supplied shall be the LDC city gate meter(s). 

(5) For an LDC using Equation NN–1 or NN–2 of this subpart, the point(s) of measurement for the natural gas volume received shall be the LDC city gate meter(s). 

NN 98.404(a)(7) (7) An LDC using Equation NN–4 of this subpart 

shall measure natural gas at the customer meters. Thereporter shall consider the volume delivered through a single particluar meter at a single particular location as the volume delivered to an individual end-user. 

(7) An LDC using Equation NN–4 of this subpart shall measure natural gas at the end-user’s meter(sWhere an end-user is known to have more than onmeter located at their facility, the reporter shall measure the natural gas at each meter and sum the annual volume delivered to all meters located at thend-user’s facility to determine the total volume delivered to the end- user. Otherwise, the reporter shall consider the total annual volume delivered through each single meter at a single particular location to be the the volume delivered to an individual end-user. 

NN 98.404(a)(8) (8) An LDC using Equation NN–5 of this subpart 

shall measure natural gas as follows: (i) Fuel1 shall be measured at the on-system storage injection meters and/or at the meters measuring natural gas to be liquefied. 

(8) An LDC using Equation NN–5a and/or NN-5b this subpart shall measure natural gas as follows: (i) Fuel1 shall be measured at the on-system storaginjection meters and/or at the meters measuring natural gas to be liquefied. 
77

Subpart Requirement Current Rule Text Proposed Rule Text 

(ii) Fuel2 shall be measured at the meters used for measuring on-system storage withdrawals and/or LNG vaporization injection. If Fuel2 is from a source other than storage, the appropriate meter shall be used to measure the quantity. 

(ii) Fuel2 shall be measured at the meters used for measuring on-system storage withdrawals and/or LNG vaporization injection. (iii) Fuelz shall be measured using established business practices. 

NN 98.404(a)(9) (9) An LDC shall measure all natural gas under the 

following standard industry temperature and pressure conditions: Cubic foot of gas at a temperature of 60 degrees Fahrenheit and at an absolute pressure of fourteen and seventy-three hundredths (14.73) pounds per square inch. 

(9) An LDC shall measure all natural gas under the following standard industry temperature and pressuconditions: Cubic foot of gas at a temperature of 6degrees Fahrenheit and at an absolute pressure of oatmosphere. 

NN 98.404(c )(2) (2) When a reporter used the default EF provided in 

this section to calculate Equation NN–2, NN–3, NN–4, NN–5, or NN–7 of this subpart, the appropriate value shall be taken from Table NN–2 of this subpart. 

(2) When a reporter used the default EF provided ithis section to calculate Equation NN-2, NN-3, NN4, NN-5a, NN-5b, or NN-7 of this subpart, the appropriate value shall be taken from Table NN-2 this subpart. 

NN 98.404(d)(1) (1) Equipment used to measure quantities in 

Equations NN–1, NN–2, and NN–5 of this subpart shall be calibrated prior to its first use for reporting under this subpart, using a suitable standard method published by a consensus based standards organization or according to the equipment manufacturer's directions. 

(1) Equipment used to measure quantities in Equations NN–1, NN–2, NN–5a and NN-5b of thisubpart shall be calibrated prior to its first use for reporting under this subpart, using a suitable standard method published by a consensus based standards organization or according to the equipmemanufacturer's directions. 

NN 98.404(d)(2) (2) Equipment used to measure quantities in 

Equations NN–1, NN–2, and NN–5 of this subpart shall be recalibrated at the frequency specified by the standard method used or by the manufacturer's directions. 

(2) Equipment used to measure quantities in Equations NN–1, NN–2, NN–5a, and NN-5b of thisubpart shall be recalibrated at the frequency specified by the standard method used or by the manufacturer's directions. 

NN 98.404(d)(3) [(None)] (3) Equipment used to measure quantities in 

Equations NN-3, and NN-4 of this subpart shall be recalibrated at the frequency commonly used withithe industry. 

NN 98.404(a)(5) 5) For an LDC using Equation NN–1 or NN–2 of 

this subpart, the point(s) of measurement for the natural gas volume supplied shall be the LDC city gate meter(s). 

5) For an LDC using Equation NN–1 or NN–2 of this subpart, the point(s) of measurement for the natural gas volume received shall be the LDC city gate meter(s). 

NN 98.405( c)(3) (3) Whenever a NGL fractionator cannot follow the 

quality assurance procedures for developing a reporter-specific HHV, as specified in §98.404, 

(3) [Reserved] 
78

Subpart Requirement Current Rule Text Proposed Rule Text 

during any period for any reason, the NGL fractionator shall use the default HHV provided in Table NN–1 of this part for that period. 

NN 98.406(a)(4) (4) Annual quantity (in barrels) of y-grade, bulk 

NGLs received from others for fractionation. 

(4) Annual quantities (in barrels) of y-grade, o-graand other bulk NGLs: (i) received. (ii) Supplied to downstream users that are not fractionated by the reporter. 

NN 98.406(a)(7) (7) Annual CO2 mass emissions (metric tons) that 

would result from the combustion or oxidation of fractionated NGLs supplied less the quantity received by other fractionators, calculated in accordance with §98.403(c)(2). 

(7) Annual CO2 mass emissions (metric tons) that would result from the combustion or oxidation of fractionated NGLs supplied less the quantity received from other fractionators, calculated in accordance with §98.403(c)(2). If the calculated value is negative, the reporter shall report the value as zero. 

NN 98.406(b)(2) (2) Annual volume in Mscf of natural gas placed into 

storage. 

(2) Annual volume in Mscf of natural gas placed into storage or liquified and stored (Fuel 1 in Equation NN-5a). 

NN 98.406(b)(3) (3) Annual volume in Mscf of vaporized liquefied 

natural gas (LNG) produced at on-system vaporization facilities for delivery on the distribution system that is not accounted for in paragraph (b)(1) of this section. 

(3) Annual volume in Mscf of natural gas withdrawfrom on-system storage and annual volume in Mscof vaporized liquefied natural gas (LNG) produced on-system vaporization facilities withdrawn from storage for delivery on the distribution system (Fue

in Equation NN-5a). 

NN 98.406(b)(4) (4) Annual volume in Mscf of natural gas withdrawn 

from on-system storage (that is not delivered to the city gate) for delivery on the distribution system. 

(4) [Reserved] 

NN 98.406(b)(5) (5) Annual volume in Mscf of natural gas delivered 

directly to LDC systems from producers or natural gas processing plants from local production. 

(5) Annual volume in Mscf of natural gas that bypassed the city gate(s) and was supplied through the LDC distribution system. This includes natural gas from producers and natural gas processing planfrom local production, or natural gas that was vaporized upon receipt and delivered, and any othesource that bypassed the city gate (Fuelz in EquatiNN-5b). 

NN 98.406(b)(7) (7) Annual volume in Mscf of natural gas delivered 

by LDC to each meter registering supply equal to or greater than 460,000 Mcsf during the calendar year. 

(7) Annual volume in Mscf of natural gas delivered by the LDC to each end-user facility that received from the LDC deliveries equal to or greater than 460,000 Mscf during the calendar year, if known; 
79

Subpart Requirement Current Rule Text Proposed Rule Text 

otherwise, report the annual volume in Mscf of natural gas delivered by the LDC to each meter registering supply equal to or greater than 460,000 Mscf during the calendar year. 

NN 98.406(b)(9) (9) Annual CO2 emissions (metric tons) that would 

result from the complete combustion or oxidation of the annual supply of natural gas to end-users registering less than 460,000 Mcsf, calculated in accordance with §98.403(b)(4). 

(9) Annual CO2 emissions (metric tons) that would result from the complete combustion or oxidation othe annual supply of natural gas to end-users registering less than 460,000 Mscf, calculated in accordance with §98.403(b)(4). If the calculated value is negative, the reporter shall report the value as zero. 

NN 98.406(b)(12) (12) The customer name, address, and meter number 

of each meter reading used to report in paragraph (b)(7) of this section. 

(12) The customer name, address, and meter numbof each end-user reported in paragraph (b)(7) of thsection. Additionally, report whether the quantity onatural gas reported in paragraph (b)(7) of this section is the total quantity delivered to the end-usor the quantity delivered to a specific meter. 

NN 98.407

Introductory Paragraph 

98.407 Records that must be retained. In addition to the information required by §98.3(g), each annual report must contain the following information: 

98.407 Records that must be retained. In addition to the information required by §98.3(g)the reporter shall retain the following records: 

NN 98.408 - Table NN-1 Table NN–1 to Subpart HH of Part 98—Default Factors for Calculation Methodology 1 of This 

Subpart 

See Appendix A for changes to Table NN-1 

NN 98.408 - Table NN-2 Table NN–2 to Subpart HH of Part 98—Lookup Default Values for Calculation Methodology 2 of 

This Subpart 

See Appendix A for changes to Table NN-2 

PP 98.423(a)(3)(i

) 

(3) To aggregate data, use either Equation PP–3a or PP–3b in this paragraph, as appropriate. (i) For facilities with production process units that capture a CO2 stream and either measure it after segregation or do not segregate the flow, calculate the total CO2 supplied in accordance with Equation PP–3a. 

(3) To aggregate data, use either Equation PP–3a oPP–3b in this paragraph, as appropriate. (i) For facilities with production process units or production wells that capture or extract a CO2 strea

and either measure it after segregation or do not segregate the flow, calculate the total CO2 supplied in accordance with Equation PP–3a. 

PP 98.426(b)(4)(

i) and (ii) 

(4) Report density as follows:(i) Quarterly density of CO2 in metric tons per 

standard cubic meter if you report the concentration of the CO2 stream in paragraph (b)(3) of this section in weight percent. 

(4) Report density as follows:(i) Quarterly density of the CO2 stream in metric toper standard cubic meter if you report the concentration of the CO2 stream in paragraph (b)(3of this section in weight percent. 
80

Subpart Requirement Current Rule Text Proposed Rule Text 

(ii) Quarterly density of the CO2 stream in metric tons per standard cubic meter if you report the concentration of the CO2 stream in paragraph (b)(3) 

of this section in volume percent. 

(ii) Quarterly density of CO2 in metric tons per standard cubic meter if you report the concentratioof the CO2 stream in paragraph (b)(3) of this sectioin volume percent. 

PP 98.426(f)(10) (10) Enhanced oil and natural gas recovery (10) Injection of CO2 for enhanced oil and natural 

gas recovery that is covered by subpart UU of this part. 

PP 98.426(f)(11) (11) Long-term storage (sequestration) (11) Geologic sequestration of carbon dioxide that 

covered by subpart RR of this part. 

QQ 98.433(a) St = Mass of fluorinated GHG per unit of equipment 

type t or foam type t (charge per piece of equipment or cubic foot of foam, kg). 

St = Mass of fluorinated GHG per unit of equipmentype t or foam type t (charge per piece of equipmenkg) or density of fluorinated GHG in foam (charge per cubic foot of foam, kg per cubic foot). 

QQ 98.433(b) St = Mass in CO2e of the fluorinated GHGs per unit 

of equipment type t or foam type t (charge per piece of equipment or cubic foot of foam, kg). 

St = Mass in CO2e of the fluorinated GHGs per uniof equipment type t or foam type t (charge per piecof equipment, kg) or density of fluorinated GHG in foam (CO2e per cubic foot of foam, kg CO2e per cubic foot). 

QQ 98.434(b) (b) The inputs to the annual submission must be 

reviewed against the import or export transaction records to ensure that the information submitted to EPA is being accurately transcribed as the correct chemical or blend in the correct pre-charged equipment or closed-cell foam in the correct quantities (metric tons) and units (kg per piece of equipment or cubic foot of foam). 

(b) The inputs to the annual submission must be reviewed against the import or export transaction records to ensure that the information submitted to EPA is being accurately transcribed as the correct chemical or blend in the correct pre-charged equipment or closed-cell foam in the correct quantities and units. 

QQ 98.436(a)(3) (3) For closed-cell foams that are imported inside of 

appliances, the identity of the fluorinated GHG contained in the foam in each appliance, the mass of the fluorinated GHG contained in the foam in each appliance, and the number of appliances imported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams. 

(3) For closed-cell foams that are imported inside oequipment, the identity of the fluorinated GHG contained in the foam in each appliance, the mass the fluorinated GHG contained in the foam in each piece of equipment, and the number of pieces of equipment imported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams. 

QQ 98.436(a)(4) (4) For closed cell-foams that are not imported inside 

of appliances, the identity of the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam imported (cubic feet) for each type 

(4) For closed cell-foams that are not imported insiof equipment, the identity of the fluorinated GHG the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam imported (cubic feet) for each type 
81

Subpart Requirement Current Rule Text Proposed Rule Text 

of closed-cell foam with a unique combination of fluorinated GHG density and identity. 

of closed-cell foam with a unique combination of fluorinated GHG density and identity. 

QQ 98.436(a)(5) (5) Dates on which the pre-charged equipment or 

closed-cell foams were imported. 

(5) [Reserved.] 

QQ 98.436(a)(6)(i

i) 

(ii) For closed-cell foams that are imported inside of appliances, the mass of the fluorinated GHGs in CO2e contained in the foam in each appliance and the number of appliances imported for each type of appliance. 

(ii) For closed-cell foams that are imported inside equipment, the mass of the fluorinated GHGs in CO2e contained in the foam in each piece of equipment and the number of pieces of equipment imported for each equipment type. 

QQ 98.436(a)(6)(i

ii) 

(iii) For closed-cell foams that are not imported inside of appliances, the mass in CO2e of the fluorinated GHGs in the foam (kg CO2e/cubic foot) and the volume of foam imported (cubic feet) for each type of closed-cell foam. 

(iii) For closed-cell foams that are not imported inside of equipment, the density in CO2e of the fluorinated GHGs in the foam (kg CO2e/cubic fooand the volume of foam imported (cubic feet) for each type of closed-cell foam. 

QQ 98.436(a)(6)(i

v) 

(iv) Dates on which the closed-cell foams were imported. 

(iv) [Reserved.] 

QQ 98.436(b)(3) (3) For closed-cell foams that are exported inside of 

appliances, the identity of the fluorinated GHG contained in the foam in each appliance, the mass of the fluorinated GHG contained in the foam in each appliance, and the number of appliances exported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams. 

(3) For closed-cell foams that are exported inside oequipment, the identity of the fluorinated GHG contained in the foam in each piece of equipment, the mass of the fluorinated GHG contained in the foam in each piece of equipment, and the number pieces of equipment exported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams. 

QQ 98.436(b)(4) (4) For closed-cell foams that are not exported inside 

of appliances, the identity of the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam exported (cubic feet) for each type of closed-cell foam with a unique combination of fluorinated GHG density and identity. 

(4) For closed-cell foams that are not exported insiof equipment, the identity of the fluorinated GHG the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam exported (cubic feet) for each type of closed-cell foam with a unique combination of fluorinated GHG density and identity. 

QQ 98.436(b)(5) (5) Dates on which the pre-charged equipment or 

closed-cell foams were exported. 

(5) [Reserved.] 

QQ 98.436(b)(6)(

ii) 

(ii) For closed-cell foams that are exported inside of appliances, the mass of the fluorinated GHGs in CO2e contained in the foam in each appliance and the number of appliances imported for each type of 

(ii) For closed-cell foams that are exported inside oequipment, the mass of the fluorinated GHGs in CO2e contained in the foam in each piece of equipment and the number of pieces of equipment 
82

Subpart Requirement Current Rule Text Proposed Rule Text 

appliance. imported for each equipment type.

QQ 98.436(b)(6)(

iii) 

(iii) For closed-cell foams that are not exported inside of appliances, the mass in CO2e of the fluorinated GHGs in the foam (kg CO2 e/cubic foot) and the volume of foam imported (cubic feet) for each type of closed-cell foam. 

(iii) For closed-cell foams that are not exported inside of equipment, the density in CO2e of the fluorinated GHGs in the foam (kg CO2 e/cubic fooand the volume of foam imported (cubic feet) for each type of closed-cell foam. 

QQ 98.436(b)(6)i

v) 

(6)(iv) Dates on which the closed-cell foams were exported. 

(6)(iv) [Reserved.] 

QQ 98.438 Closed-cell foam means any foam product, excluding 

packaging foam that is constructed with a closed-cell structure and a blowing agent containing a fluorinated GHG. Closed-cell foams include but are not limited to polyurethane (PU) appliance foam, PU continuous and discontinuous panel foam, PU one component foam, PU spray foam, extruded polystyrene (XPS) boardstock foam, and XPS sheet foam. Packaging foam means foam used exclusively during shipment or storage to temporarily enclose items. 

Closed-cell foam means any foam product, excludipackaging foam that is constructed with a closed-cstructure and a blowing agent containing a fluorinated GHG. Closed-cell foams include but arnot limited to polyurethane (PU) foam contained in equipment, PU continuous and discontinuous panefoam, PU one component foam, PU spray foam, extruded polystyrene (XPS) boardstock foam, and XPS sheet foam. Packaging foam means foam used exclusively during shipment or storage to temporarily enclose items.

QQ 98.438 Pre-charged electrical equipment component means 

any portion of electrical equipment that is charged with SF6 or PFCs prior to sale or distribution or offer for sale or distribution in interstate commerce. 

Pre-charged electrical equipment component meanany portion of electrical equipment that is charged with a fluorinated greenhouse gas prior to sale or distribution or offer for sale or distribution in interstate commerce. 

RR 98.443 (b)(2) Sr,p= Quarterly mass of contents in containers r that

is redelivered to another facility without being injected into your well in quarter p (metric tons) 

Sr,p= Quarterly volume of contents in containers r that is redelivered to another facility without being injected into your well in quarter p (standard cubic meters) 

RR 98.443(d)(3) (3) To aggregate production data, you must sum the 

mass of all of the CO2 separated at each gas-liquid 

separator in accordance with the procedure specified in Equation RR–9 of this section. You must assume that the total CO2 measured at the separator(s) represents a percentage of the total CO2 produced. In order to account for the percentage of CO2 produced that is estimated to remain with the produced oil or other fluid, you must multiply the quarterly mass of CO2 measured at the separator(s) by a percentage estimated using a methodology in your approved 

(3) To aggregate production data, you must sum thmass of all of the CO2 separated at each gas-liquid separator in accordance with the procedure specifiein Equation RR–9 of this section. You must assumthat the total CO2 measured at the separator(s) 

represents a percentage of the total CO2 produced. order to account for the percentage of CO2 producethat is estimated to remain with the produced oil or other fluid, you must multiply the quarterly mass oCO2 measured at the separator(s) by a percentage estimated using a methodology in your approved 
83

Subpart Requirement Current Rule Text Proposed Rule Text 

MRV plan. If fluids containing CO2 from injection wells covered under this source category are produced and not processed through a gas-liquid separator, the concentration of CO2 in the produced fluids must be measured at a flow meter located prior to reinjection or reuse using methods in §98.444(f)(1). The considerations you intend to use to calculate CO2 from produced fluids for the mass 

balance equation must be described in your approved MRV plan in accordance with §98.448(d)(5). 

MRV plan. If fluids containing CO2 from injection wells covered under this source category are produced and not processed through a gas-liquid separator, the concentration of CO2 in the produced fluids must be measured at a flow meter located prto reinjection or reuse using methods in §98.444(f)(1). The considerations you intend to usto calculate CO2 from produced fluids for the mass balance equation must be described in your approvMRV plan in accordance with §98.448(a)(5). 

RR 98.443(f)(2) CO2FI = Total annual CO2 mass emitted (metric tons) 

from equipment leaks and vented emissions of CO2from equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead. 

CO2FI = Total annual CO2 mass emitted (metric tonfrom equipment leaks and vented emissions of COfrom equipment located on the surface between the flow meter used to measure injection quantity and the injection wellhead, for which a calculation procedure is provided in subpart W of this part. 

RR 98.446(b)(5) (5) The standard or method used to calculate each 

value in paragraphs (b)(1) and (b)(2) of this section. 

(5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of thisection. 

SS 98.453(d) (d) Estimate the mass of SF6 or PFCs disbursed to 

customers in new equipment or cylinders over the period p by monitoring the mass flow of the SF6 or PFCs into the new equipment or cylinders using a flowmeter or by weighing containers before and after gas from containers is used to fill equipment or cylinders. 

(d) Estimate the mass of SF6 or PFCs disbursed to customers in new equipment or cylinders over the period p by monitoring the mass flow of the SF6 or PFCs into the new equipment or cylinders using a flowmeter, or by weighing containers before and after gas from containers is used to fill equipment cylinders, or by using the nameplate capacity of thequipment. 

SS 98.453(h) (h) The mass of SF6 or the PFC disbursed to 

customers in new equipment over the period p must be determined either by using the nameplate capacity of the equipment or, in cases where equipment is shipped with a partial charge, by calculating the partial shipping charge. Calculate the partial shipping charge by multiplying the nameplate capacity of the equipment by the ratio of the densities of the partial charge to the full charge. To determine the equipment's actual nameplate capacity, you must measure the nameplate capacities of a representative sample of each make and model 

(h) If the mass of SF6 or the PFC disbursed to customers in new equipment or cylinders over the period p is determined by using the nameplate capacity, or by using the nameplate capacity of the equipment and calculating the partial shipping charge, use the methods in either paragraph (h)(1) (h)(2) of this section. (1) Determine the equipment's actual nameplate capacity, by measuring the nameplate capacities of representative sample of each make and model and calculating the mean value for each make and modas specified at §98.454(f); 
84

Subpart Requirement Current Rule Text Proposed Rule Text 

and take the average for each make and model as specified at §98.454(f). 

(2) If equipment is shipped with a partial charge, calculate the partial shipping charge by multiplying the nameplate capacity of the equipment by the ratof the densities of the partial charge to the full charge. 

SS 98.453(i) MF = The total annual mass of the SF6 or PFCs, in 

pounds, used to fill equipment. 

MF = The total annual mass of the SF6 or PFCs, in pounds, used to fill equipment during equipment installation at electric transmission or distribution facilities. 

SS 98.456(m) (m) The values for each hose and valve combination 

and the associated valve fitting sizes and hose diameters. 

(m) The values for EFCi of Equation SS-5 of this subpart for each hose and valve combination and thassociated valve fitting sizes and hose diameters. 

SS 98.456(o) & 

(p) 

(o) The mean value for each make, model, and group of conditions if the mass of SF6 or the PFC disbursed to customers in new equipment over the period p is determined by assuming that it is equal to the equipment's nameplate capacity or, in cases where equipment is shipped with a partial charge, equal to its partial shipping charge. (p) The number of samples and the upper and lower bounds on the 95 percent confidence interval for each make, model, and group of conditions if the mass of SF6 or the PFC disbursed to customers in new equipment over the period p is determined by assuming that it is equal to the equipment's nameplate capacity or, in cases where equipment is shipped with a partial charge, equal to its partial shipping charge. 

(o) If the mass of SF6 or the PFC disbursed to customers in new equipment over the period p is determined according to the methods required in §98.453(h) of this subpart, report the mean value onameplate capacity in pounds for each make, modeand group of conditions. (p) If the mass of SF6 or the PFC disbursed to customers in new equipment over the period p is determined according to the methods required in §98.453(h) of this subpart, report the number of samples and the upper and lower bounds on the 95 percent confidence interval for each make, model, and group of conditions. 

TT 98.460(c)(2)(

xiii) 

(xiii) Other waste material that has a DOC value of 0.3 weight percent (on a wet basis) or less. DOC value must be determined using a 60-day anaerobic biodegradation test procedure identified in § 98.464(b)(4)(i)(A) . 

(xiii) Other waste material that has a DOC value of 0.3 weight percent (on a wet basis) or less. DOC value must be determined using a 60-day anaerobic biodegradation test procedure identified in § 98.464(b)(4)(i) . 

TT 98.463(a)(1) DOCF= Fraction of DOC dissimilated (fraction); use 

the default value of 0.5. 

DOCF= Fraction of DOC dissimilated (fraction); uthe default value of 0.5. If measured values of DOC are available using the 60-day anaerobic biodegradation test procedure identified in 
85

Subpart Requirement Current Rule Text Proposed Rule Text 

98.464(b)(4)(i), use a default value of 1.0 .

TT 98.463(a)(1)

Eq. TT-1 

Fx = Fraction by volume of CH4 in landfill gas (fraction, dry basis, corrected to 0% oxygen). If you have a gas collection system, use the annual average CH4 concentration from measurement data for the current reporting year; otherwise, use the default value of 0.5. 

F = Fraction by volume of CH4 in landfill gas (fraction, dry basis, corrected to 0% oxygen). If yohave a gas collection system, use the annual averagCH4 concentration from measurement data for the current reporting year; otherwise, use the default value of 0.5. 

TT 98.463(a)(2)(i

i)(C ) Eq. TT-4b 

TT 98.463(b)(1) 

Eq. TT-6 

OX = Oxidation fraction. Use the default value of 0.1 (10 percent). 

OX = Oxidation fraction from Table HH-4 of subpHH of this part. 

TT 98.464(b) (b) For each waste stream placed in the landfill 

during the reporting year for which you choose to determine volatile solids concentration for the purposes of § 98.460(c)(2)(xii) or choose to determine a landfill-specific DOCX for use in Equation TT-1 of this subpart or for the purposes of § 98.460(c)(2)(xiii) of this subpart, you must collect and test a representative sample of that waste stream using the methods specified in paragraphs (b)(1) through (b)(4) of this section. 

(b) For each waste stream placed in the landfill during the reporting year for which you choose to determine volatile solids concentration and/or a waste stream-specific DOCX, you must collect and test a representative sample of that waste stream using the methods specified in paragraphs (b)(1) through (b)(4) of this section, as applicable. 

TT 98.464(b)(4)(

i)(E) Eq. TT-7 

Where:DOCX= Degradable organic content of the waste stream in YearX (weight fraction, wet basis) DOCF= Fraction of DOC dissimilated (fraction); use the default value of 0.5.MCDsample,x= Mass of carbon degraded in the waste stream sample in Year X as determined in paragraph (b)(4)(i)(C) of this 

Where: DOCX= Degradable organic content of the waste stream in Year X (weight fraction, wet basis) MCDsample,x= Mass of carbon degraded in the waste stream sample in Year X as determined in paragrap(b)(4)(i)(C) of this section [milligrams (mg)]. Msample,x= Mass of waste stream sample used in the anaerobic degradation test in Year X (mg, wet basi

∑− NYrData n Wmeas n 1 , ∑= NYrData n Wmeas n 1 ,

     = control control sample x sample x F X MC MCD MMCD DOC DOC , 1 , sample x sample x X MMCD Doc , , =
86

Subpart Requirement Current Rule Text Proposed Rule Text 

section [milligrams (mg)].Msample,x= Mass of waste stream sample used in the anaerobic degradation test in Year X (mg, wet basis). MCDcontrol= Mass of carbon degraded in the control sample as determined in paragraph (b)(4)(i)(B) of this section (mg).MCcontrol= Mass of carbon added to the control sample via the substrate material in the anaerobic degradation (mg). 

TT 98.464(c) (c) For each waste stream for which you choose to 

determine volatile solids concentration for the purposes of paragraph § 98.460(c)(2)(xii), and that was historically managed in the landfill but was not received during the first reporting year, you must determine volatile solids concentration of the waste stream as initially placed in the landfill using the methods specified in paragraph (c)(1) or (c)(2) of this section, as applicable. 

(c) For each waste stream that was historically managed in the landfill but was not received during the first reporting year for which you choose to determine volatile solids concentration and/or a waste stream-specific DOCX, you must determine volatile solids concentration or DOCX of the waste 

stream as initially placed in the landfill using the methods specified in paragraph (c)(1) or (c)(2) of this section, as applicable. 

TT 98.464(c)(1) (1) If you can identify a similar waste stream to the 

waste stream that was historically managed in the landfill, you must determine the volatile solids concentration of the similar waste stream using the procedures in paragraphs (b)(1) through (b)(3) of this section. 

(1) If you can identify a similar waste stream to the waste stream that was historically managed in the landfill, you must determine the volatile solids concentration or DOCX of the similar waste stream using the applicable procedures in paragraphs (b)(through (b)(4) of this section. 

TT 98.464(c)(2) (2) If you cannot identify a similar waste stream to 

the waste stream that was historically managed in the landfill, you may determine the volatile solids concentration of the historically managed waste stream using process knowledge. You must document the basis for volatile solids concentration as determined through process knowledge. 

(2) If you cannot identify a similar waste stream to the waste stream that was historically managed in tlandfill, you may determine the volatile solids concentration or DOCX of the historically managed waste stream using process knowledge. You must document the basis for the volatile solids concentration or DOCX value as determined througprocess knowledge. 

TT 98.466(b)(1) (1) The number of waste steams (including “Other 

Industrial Solid Waste (not otherwise listed)”) for which Equation TT-1 of this subpart is used to calculate modeled CH4 generation. 

(1) The number of waste steams (including “Other Industrial Solid Waste (not otherwise listed)” and “Inerts ”) for which Equation TT–1 of this subpart used to calculate modeled CH4 generation. 

TT 98.466(b)(5) (None) (5) For each waste stream, the decay rate (k) value 

used in the calculations. 

TT 98.466(c ) (c) For each waste stream identified in paragraph (b) 

of this section, report the following information: (1) The decay rate (k) value used in the calculations. 

(c) Report the following historical waste information: (1) [Reserved] 
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Subpart Requirement Current Rule Text Proposed Rule Text 

(2) The method(s) for estimating historical wastedisposal quantities and the range of years for which each method applies. (3) If Equation TT–2 of this subpart is used, provide:(i) The total number of years (N) for which disposal and production data are both available. (ii) The year, the waste disposal quantity and production quantity for each year used in Equation TT–2 of this subpart to calculate the average waste disposal factor (WDF). (iii) The average waste disposal factor (WDF) calculated for the waste stream. 

(2) For each waste stream identified in paragraph (of this section, the method(s) for estimating historical waste disposal quantities and the range oyears for which each method applies. (3) For each waste stream identified in paragraph (of this section for which Equation TT-2 of this subpart is used, provide: (i) The total number of years (N) for which disposaand production data are both available. (ii) The year, the waste disposal quantity and production quantity for each year used in Equation TT–2 of this subpart to calculate the average waste disposal factor (WDF). (iii) The average waste disposal factor (WDF) calculated for the waste stream. 

TT 98.466(c)(4) (4) If Equation TT-4 of this subpart is used, provide:

(i) The value of landfill capacity (LFC). (ii) YrData. (iii) YrOpen. 

(4) If Equation TT–4a of this subpart is used, provide: (i) The value of landfill capacity (LFC). (ii) YrData. (iii) YrOpen. 

TT 98.466(c)(5) (None) (5) If Equation TT-4b of this subpart is used, 

provide: (i) WIP (i.e., the quantity of waste in-place at the start of the reporting year from design drawings or engineering estimates (metric tons) or, for closed landfills for which waste in-place quantities are noavailable, the landfill's design capacity); (ii) The cumulative quantity of waste placed in the landfill for the years for which disposal quantities available from company record or from Equation TT-3 of this part; (iii) YrLast; (iv) YrOpen; and (v) NYrData. 

TT 98.466(d)(3) (3) The degradable organic carbon (DOCX ) value 

(mass fraction) for the specified year and an indication as to whether this was the default value from Table TT-1 to this subpart, a measured value 

(3) For each waste stream, the degradable organic carbon (DOCX) value (mass fraction) for the specified year and an indication as to whether this was the default value from Table TT–1 to this 
88

Subpart Requirement Current Rule Text Proposed Rule Text 

using a 60-day anaerobic biodegradation test as specified in §98.464(b)(4)(i), or a value based on total and volatile solids measurements as specified in §98.464(b)(4)(ii). If DOCX was determined by a 60-day anaerobic biodegradation test, specify the test method used. 

subpart, a measured value using a 60-day anaerobibiodegradation test as specified in §98.464(b)(4)(i)or a value based on total and volatile solids measurements as specified in §98.464(b)(4)(ii). If DOCX was determined by a 60-day anaerobic biodegradation test, specify the test method used. 

TT 98.466(h) (h) For landfills with gas collection systems, in 

addition to the reporting requirements in paragraphs (a) through (f) of this section, you must report according to §98.346(i). 

(h) For landfills with gas collection systems, in addition to the reporting requirements in paragraph(a) through (f) of this section, provide: (1) The annual methane generation, adjusted for oxidation, calculated using Equation TT-6 of this subpart, reported in metric tons CH4; 

(2) The oxidation factor used in Equation TT-6 of this subpart; and (3) All information required under 40 CFR 98.346(i)(1) through (i)(7) and 40 CFR 98.346(i)(9through (i)(12). 

TT 98.467 In addition to the information required by §98.3(g), 

you must retain the calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration, and all measurement data used for the purposes of paragraph § 98.460(c)(2)(xii) or used to determine landfill-specific DOCX values. 

In addition to the information required by §98.3(g)you must retain the calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration, aall measurement data used for the purposes of paragraphs §98.460(c)(2)(xii) or (c)(2)(xiii) or useto determine waste stream-specific DOCX values fouse in Equation TT-1 of this subpart. 

TT Table TT-1 Table TT-1 See Appendix A for changes to Table TT-1 

UU 98.473(a)(2) D= Density of CO2 at standard conditions (metric 

tons per standard cubic meter): 0.0018704 

D= Density of CO2 at standard conditions (metric tons per standard cubic meter): 0.0018682 

UU 98.473(b)(2) Sr,p= Quarterly mass of contents in containers r that 

is redelivered to another facility without being injected into your well in quarter p (standard cubic meters) 

Sr,p= Quarterly volume of contents in containers r that is redelivered to another facility without being injected into your well in quarter p (standard cubic meters) 

UU 98.476(b)(5) (5) The standard or method used to calculate each 

value in paragraphs (b)(1) and (b)(2) of this section. 

(5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of thisection. 

UU 98.476(e) (None) (e) Report the following:

(1) Whether the facility received a Research and Development project exemption from reporting 
89

Subpart Requirement Current Rule Text Proposed Rule Text 

under 40 CFR Part 98 subpart RR for this reporting year. If you received an exemption, report the start and end dates of the exemption approved by EPA; (2) Whether the facility includes a well or group of wells where a CO2 stream was injected into subsurface geologic formations to enhance the recovery of oil during this reporting year; (3) Whether the facility includes a well or group of wells where a CO2 stream was injected into subsurface geologic formations to enhance the recovery of natural gas during this reporting year; (4) Whether the facility includes a well or group of wells where a CO2 stream was injected into subsurface geologic formations for acid gas disposduring this reporting year; (5) Whether the facility includes a well or group of wells where a CO2 stream was injected for a purpoother than those listed in (e)(1)through (4) of this section. If you injected CO2 for another purpose, report the purpose of the injection. 
Attachment A 

1. Proposed Amendments to 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 124–38–9 CO2 1 

Methane 74–82–8 CH4 25a

Nitrous oxide 10024–97–2 N2O 298a

HFC–23 75–46–7 CHF3 14,800a

HFC–32 75–10–5 CH2F2 675a

HFC–41 593–53–3 CH3F 92a

HFC–125 354–33–6 C2HF5 3,500a

HFC–134 359–35–3 C2H2F4 1,100a

HFC–134a 811–97–2 CH2FCF3 1,430a

HFC–143 430–66–0 C2H3F3 353a

HFC–143a 420–46–2 C2H3F3 4,470a

HFC–152 624–72–6 CH2FCH2F 53 

HFC–152a 75–37–6 CH3CHF2 124a

HFC–161 353–36–6 CH3CH2F 12 

HFC–227ea 431–89–0 C3HF7 3,220a

HFC–236cb 677–56–5 CH2FCF2CF3 1,340 

HFC–236ea 431–63–0 CHF2CHFCF3 1,370 

HFC–236fa 690–39–1 C3H2F6 9,810a 

HFC–245ca 679–86–7 C3H3F5 693a 

HFC–245fa 460–73–1 CHF2CH2CF3 1,030 

HFC–365mfc 406–58–6 CH3CF2CH2CF3 794 

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

Sulfur hexafluoride 2551–62–4 SF6 22,800a
Name CAS No. Chemical formula 

Global warming 

potential 

(100 yr.) 

Trifluoromethyl sulphur 

pentafluoride 

373–80–8 SF5CF3 17,700 

Nitrogen trifluoride 7783–54–2 NF3 17,200 

PFC–14 (Perfluoromethane) 75–73–0 CF4 7,390a

PFC–116 (Perfluoroethane) 76–16–4 C2F6 12,200a

PFC–218 (Perfluoropropane) 76–19–7 C3F8 8,830a

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

PFC–3–1–10 (Perfluorobutane) 355–25–9 C4F10 8,860a

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

PFC–4–1–12 (Perfluoropentane) 678–26–2 C5F12 9,160a

PFC–5–1–14 

(Perfluorohexane) 

355–42–0 C6F14 9,300a

PFC–9–1–18 306–94–5 C10F18 7,500 

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

HFE–43–10pccc (H–Galden 1040x) E1730133 CHF2OCF2OC2F4OC

HF2 

1,870 

HFE–125 3822–68–2 CHF2OCF3 14,900 

HFE–134 1691–17–4 CHF2OCHF2 6,320 

HFE–143a 421–14–7 CH3OCF3 756 

HFE–227ea 2356–62–9 CF3CHFOCF3 1,540 

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

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

HFE–236fa 20193–67–3 CF3CH2OCF3 487 

HFE–245cb2 22410–44–2 CH3OCF2CF3 708 

HFE–245fa1 84011–15–4 CHF2CH2OCF3 286 

HFE–245fa2 1885–48–9 CHF2OCH2CF3 659 

HFE–254cb2 425–88–7 CH3OCF2CHF2 359 

HFE–263fb2 460–43–5 CF3CH2OCH3 11 

HFE-329mcc2 67490-36-2 CF3CF2OCF2CHF2 919 
Name CAS No. Chemical formula 

Global warming 

potential 

(100 yr.) 

HFE–338mcf2 156053–88–2 CF3CF2OCH2CF3 552 

HFE–338pcc13 (HG–01) 188690–78–0 CHF2OCF2CF2OCH

F2 

1,500 

HFE–347mcc3 28523–86–6 CH3OCF2CF2CF3 575 

HFE–347mcf2 E1730135 CF3CF2OCH2CHF2 374 

HFE–347pcf2 406–78–0 CHF2CF2OCH2CF3 580 

HFE–356mec3 382–34–3 CH3OCF2CHFCF3 101 

HFE–356pcc3 160620–20–2 CH3OCF2CF2CHF2 110 

HFE–356pcf2 E1730137 CHF2CH2OCF2CHF2 265 

HFE–356pcf3 35042–99–0 CHF2OCH2CF2CHF2 502 

HFE–365mcf3 378–16–5 CF3CF2CH2OCH3 11 

HFE–374pc2 512–51–6 CH3CH2OCF2CHF2 557 

HFE–449sl (HFE–7100) 

Chemical blend 

163702–07–6 

163702–08–7 

C4F9OCH3 

(CF3)2CFCF2OCH3 

297 

HFE–569sf2 (HFE–7200) 

Chemical blend 

163702–05–4 

163702–06–5 

C4F9OC2H5 

(CF3)2CFCF2OC2H5

59 

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

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

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

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

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

Bis(trifluoromethyl)-methanol 920–66–1 (CF3)2CHOH 195 

2,2,3,3,3-pentafluoropropanol 422–05–9 CF3CF2CH2OH 42 

PFPMIE NA CF3OCF(CF3)CF2OC

F2OCF3 

10,300 

HFC-1234ze b 29118-24-9 C3H2F4 6 

hexafluoropropylene (HFP) b 116-15-4 C3F6 0.25 

perfluoromethyl vinyl ether 

(PMVE)b 1187-93-5 CF(CF3)OCF3 

3 
Name CAS No. Chemical formula 

Global warming 

potential 

(100 yr.) 

tetrafluoroethylene (TFE)b 116-14-3 C2F4 0.02 

trifluoro propene (TFP)b 677-21-4 C3H3F3 3 

vinyl fluoride (VF)b 75-02-5 C2H3F 0.7 

vinylidiene fluoride (VF2)b 75-38-7 C2H2F2 0.9 

carbonyl fluoride b 353-50-4 COF2 2 

perfluoropropyl vinyl etherb 1623-05-8 C5F10O 3 

perfluoroethyl vinyl etherb 10493-43-3 C4F8O 3 

HFC-1234yf b 754-12-1 C3H2F4 4 

perfluorethyl iodide (2-I)b 354-64-3 C2F5I 3 

perfluorbutyl iodide (PFBI, 42-I) b 423-39-2 C4F9I 3 

perfluorhexyl iodide (6-I)b 355-43-1 

CF3CF2CF2CF2CF2

CF2IC6F13I 

2 

perfluoroctyl iodide (8-I)b 507-63-1 C8F17I 2 

1,1,1,2,2-pentafluoro-4-iodo butane 

(22-I) b 40723-80-6 C4H4F5I 

2 

1,1,1,2,2,3,3,4,4-nonafluoro-6-iodo 

hexane (42-I) b 2043-55-2 C6H4F9I 

2 

perfluorobutyl ethene (42-U)b 19430-93-4 C6H3F9 2 

perfluorohexyl ethene (62-U)b 25291-17-2 C8H3F13 1 

perfluorooctyl ethene (82-U)b 21652-58-4 C10H3F17 1 

1H,1H, 2H,2H-perfluorohexan-1-ol 

(42-AL)b 2043-47-2 C6H5F9O 

5 

FK-5-1-12 Perfluoroketone; FK-5-1-

12myy2; n-Perfluorooctane; 

Octanedecafluorooctaneb 756-13-8 

CF3CF2C(O)CF 

(CF3)2 

 1.8 

C7 Fluoroketone, Novec 774/ FK-6-

1-12 

813-44-5 and 

813-45-6 

C7F14O Chemical 

Blend 

1 

trans-1-chloro-3,3,3-trifluoroprop-1-

ene b 2730-43-0 C3H2ClF3 

7 

Hexadecofluoroheptane b

(PFC-6-1-12) 335-57-9 C7F16 

7930 
Name CAS No. Chemical formula 

Global warming 

potential 

(100 yr.) 

octadecafluorooctane b

(PFC-7-1-18) 307-34-6 C8F18 

8340 

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. 

b The GWP for this compound was not provided in the version of Table A-1 to subpart A of part 

98 published on October 30, 2009. 

NA – Not available 

3. Proposed Amendments to Table A-6 to 40 CFR part 98, subpart A: 

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. 
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) 

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. 

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 
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) 

determined using the methods in 

§98.343(a)(3)(ii), population served 

by the landfill for each year, and 

the value of landfill capacity (LFC) 

used in the calculation. 

HH 98.346(c) All. 

HH 98.346(d)(1) Only degradable organic carbon (DOC) 

value, and fraction of DOC 

dissimilated (DOCF) values. 

HH 98.346(d)(2) All. 

HH 98.346(e) Only fraction of CH4 in landfill gas 

and methane correction factor (MCF) 

values. 

HH 98.346(f) Only surface area associated with 

each cover type. 

HH 98.346(g) All. 

HH 98.346(i)(5) Only annual operating hours for the 

primary destruction device, annual 

operating hours for the backup 

destruction device, destruction 

efficiency for the primary 

destruction device, and destruction 

efficiency for the backup destruction 

device. 

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. 

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. 
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) 

II 98.356(b)(4) All. 

II 98.356(b)(5) All. 

II 98.356(d)(1) All. 

II 98.356(d)(7) All. 

II 98.356(d)(8) Only annual operating hours for the 

primary destruction device, annual 

operating hours for the backup 

destruction device, destruction 

efficiency of the primary destruction 

device, and destruction efficiency of 

the backup destruction device. 

SS 98.456(a) All. 

SS 98.456(b) All. 

SS 98.456(c) All. 

SS 98.456(d) All. 

SS 98.456(e) All. 

SS 98.456(f) All. 

SS 98.456(g) All. 

SS 98.456(h) All. 

SS 98.456(i) All. 

SS 98.456(j) All. 

SS 98.456(m) All. 

SS 98.456(n) All. 

SS 98.456(o) All. 

SS 98.456(q) All. 

SS 98.456(r) All. 

SS 98.456(s) All. 

SS 98.456(t) Only for any missing data the 

substitute parameters used to 
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) 

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(c)(1) All. 

TT 98.466(c)(4)(i) All. 

TT 98.466(c)(4)(ii) All. 

TT 98.466(c)(4)(iii) All. 

TT 98.466(d)(1) All. 

TT 98.466(d)(2) Only degradable organic carbon (DOCX) 

value used in calculations. 

TT 98.466(d)(3) Only fraction of CH4 in landfill gas.

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. 

 
4. Proposed Amendments to Table C-1 to 40 CFR part 98, subpart C: 

Table C–1 to Subpart C—Default CO2 Emission Factors and High Heat 

Values for Various Types of Fuel

Fuel type Default high heat value 

Default CO2

emission factor 

Coal and coke mmBtu/short ton kg CO2/mmBtu

Anthracite 25.09 103.69

Waste Anthracite (Culm) See footnote 1 103.69

Bituminous 24.93 93.28

Waste Bituminous (Gob) See footnote 1 93.28

Subbituminous 17.25 97.17

Lignite 14.21 97.72

Coal Coke 24.80 113.67

Mixed (Commercial sector) 21.39 94.27

Mixed (Industrial coking) 26.28 93.90

Mixed (Industrial sector) 22.35 94.67

Mixed (Electric Power sector) 19.73 95.52

Natural gas mmBtu/scf kg CO2/mmBtu

(Weighted U.S. Average) 1.026 × 10−3 53.06

Petroleum products mmBtu/gallon kg CO2/mmBtu

Distillate Fuel Oil No. 1 0.139 73.25

Distillate Fuel Oil No. 2 0.138 73.96

Distillate Fuel Oil No. 4 0.146 75.04

Residual Fuel Oil No. 5 0.140 72.93

Residual Fuel Oil No. 6 0.150 75.10

Used Oil 0.138 74.00

Kerosene 0.135 75.20

Liquefied petroleum gases (LPG)2 0.092 61.71

Propane2 0.091 62.87

Propylene2 0.091 67.77

Ethane2 0.068 59.60
Fuel type Default high heat value 

Default CO2

emission factor 

Ethanol 0.084 68.44

Ethylene3 0.058 65.96

Isobutane2 0.099 64.94

Isobutylene2 0.103 68.86

Butane2 0.103 64.77

Butylene2 0.105 68.72

Naphtha (<401 deg F) 0.125 68.02

Natural Gasoline 0.110 66.88

Other Oil (>401 deg F) 0.139 76.22

Pentanes Plus 0.110 70.02

Petrochemical Feedstocks 0.125 71.02

Petroleum Coke 0.143 102.41

Special Naphtha 0.125 72.34

Unfinished Oils 0.139 74.54

Heavy Gas Oils 0.148 74.92

Lubricants 0.144 74.27

Motor Gasoline 0.125 70.22

Aviation Gasoline 0.120 69.25

Kerosene-Type Jet Fuel 0.135 72.22

Asphalt and Road Oil 0.158 75.36

Crude Oil 0.138 74.54

Other fuels-solid mmBtu/short ton kg CO2/mmBtu

Municipal Solid Waste 9.954 90.7

Tires 28.00 85.97

Plastics 38.00 75.00

Petroleum Coke 30.00 102.41

Other fuels—gaseous mmBtu/scf kg CO2/mmBtu

Blast Furnace Gas 0.092 × 10−3 274.32
Fuel type Default high heat value 

Default CO2

emission factor 

Coke Oven Gas 0.599 × 10−3 46.85

Propane Gas 2.516 × 10−3 61.46

Fuel Gas5 1.388 × 10−3 59.00

Biomass fuels—solid mmBtu/short ton kg CO2/mmBtu

Wood and Wood Residuals(dry basis)6 17.48 93.80

Agricultural Byproducts 8.25 118.17

Peat 8.00 111.84

Solid Byproducts 10.39 105.51

Biomass fuels—gaseous mmBtu/scf kg CO2/mmBtu

Landfill Gas 0.485 × 10−3 52.07

Other Biomass Gases 0.655 x 10-3 52.07

Biomass Fuels—Liquid mmBtu/gallon kg CO2/mmBtu

Ethanol 0.084 68.44

Biodiesel (100%) 0.128 73.84

Rendered Animal Fat 0.125 71.06

Vegetable Oil 0.120 81.55

1 Provisions of the rule referencing “default HHVs from Table C-1” do 

not apply to culm and gob. The HHV for culm and gob must be 

determined according to the procedures specified in the Tier 2 

Calculation Methodology. 

2 The HHV for components of LPG determined at 60oF and saturation 

pressure with the exception of ethylene. 

3Ethylene HHV determined at 41oF (5oC) and saturation pressure. 

4Use of this default HHV is allowed only for: (a) Units that combust 

MSW, do not generate steam, and are allowed to use Tier 1; (b) units 

that derive no more than 10 percent of their annual heat input from 

MSW and/or tires; and (c) small batch incinerators that combust no 

more than 1,000 tons of MSW per year. 

5Reporters subject to subpart X of this part that are complying with 

§98.243(d) or subpart Y of this part may only use the default HHV and 

the default CO2 emission factor for fuel gas combustion under the 

conditions prescribed in §98.243(d)(2)(i) and (d)(2)(ii) and 

§98.252(a)(1) and (a)(2), respectively. Otherwise, reporters subject 
to subpart X or subpart Y shall use either Tier 3 (Equation C–5) or 

Tier 4. 

6Use the following formula to calculate a wet basis HHV for use in 

Equation C-1: HHVw=((100-M)/100)*HHVd where HHVw = wet basis HHV, M = 

moisture content(percent) and HHVd=dry basis HHV from Table C-1. 

5. Proposed Amendments to Table C-2 to 40 CFR part 98, subpart C: 

Table C–2 to Subpart C—Default CH4 and N2O Emission Factors for 

Various Types of Fuel

Fuel type 

Default CH4 emission 

factor (kg CH4/mmBtu)

Default N2O emission 

factor (kg N2O/mmBtu)

Coal and Coke (All fuel types in Table 

C–1)1

1.1 × 10−02 1.6 × 10−03

Anthracite for FBCs only2 1.1 x 10-02 1.6 x 10-01

Waste Anthracite (Culm) for FBCs only21.1 x 10-02 4.0 x 10-01

Bituminous for FBCs only2 1.1 x 10-02 1.3 x 10-01

Waste Bituminous (Gob) for FBCs only2 1.1 x 10-02 2.9 x 10-01

Subbituminous for FBCs only2 1.1 x 10-02 6.5 x 10-02

Lignite for FBCs only2 1.1 x 10-02 1.1 x 10-01

Natural Gas 1.0 × 10−03 1.0 × 10−04

Petroleum (All fuel types in Table C–1) 3.0 × 10−03 6.0 × 10−04

Fuel Gas 3.0 × 10−03 6.0 × 10−04

Municipal Solid Waste 3.2 × 10−02 4.2 × 10−03

Tires 3.2 × 10−02 4.2 × 10−03

Blast Furnace Gas 2.2 × 10−05 1.0 × 10−04

Coke Oven Gas 4.8 × 10−04 1.0 × 10−04

Biomass Fuels—Solid (All fuel types in 

Table C–1, except wood and wood 

residuals) 

3.2 × 10−02 4.2 × 10−03

Wood and wood residuals 7.2 x 10-3 3.6 x 10-3

Biomass Fuels-Gaseous (All fuel types in 

Table C-1) 

3.2 × 10−03 6.3 × 10−04

Biomass Fuels—Liquid (All fuel types in 

Table C–1) 

1.1 × 10−03 1.1 × 10−04
1Use of the default emission factors for the coal and coke category may 

not be used to estimate emissions from combusting anthracite, waste 

anthracite, bituminous, waste bituminous, subbituminous, or lignite 

coal burned in an FBC. 

2Use of these default emission factors is required for FBCs burning the 

specified coal type. 

Note: Those employing this table are assumed to fall under the IPCC 

definitions of the “Energy Industry” or “Manufacturing Industries and 

Construction”. In all fuels except for coal the values for these two 

categories are identical. For coal combustion, those who fall within 

the IPCC “Energy Industry” category may employ a value of 1g of 

CH&ihel4;/mmBtu. 

 
6. Proposed Amendments to Table AA-1 to 40 CFR part 98, subpart AA: 

Table AA–1 to Subpart AA of Part 98—Kraft Pulping Liquor 

Emissions Factors for Biomass-Based CO2, CH4, and N2O 

Wood furnish 

Biomass-based emissions factors 

(kg/mmBtu HHV) 

CO2

a CH4 N2O 

North American Softwood 94.4 0.0019 0.00042

North American Hardwood 93.7 0.0019 0.00042

Bagasse 95.5 0.0019 0.00042

Bamboo 93.7 0.0019 0.00042

Straw 95.1 0.0019 0.00042

aIncludes emissions from both the recovery furnace and pulp mill lime 

kiln. 

7. Proposed Amendments to Table AA-2 to 40 CFR part 98, subpart AA: 

Table AA–2 to Subpart AA of Part 98—Kraft Lime Kiln and Calciner 

Emissions Factors for CH4 and N2O 

Fuel 

Fossil fuel-based emissions factors (kg/mmBtu HHV)

Kraft lime kilns Kraft calciners 

CH4 N2O CH4 N2O 

Residual Oil 

(any type) 

0.0027 0 0.0027 0.0003

Distillate Oil

(any type) 

0.0027 0 0.0027 0.0004

Natural Gas 0.0027 0 0.0027 0.0001

Biogas 0.0027 0 0.0027 0.0001

Petroleum coke 0.0027 0 NAa NAa

Other Fuels See Table 

C-2 

0 See Table 

 C-2 

See Table 

 C-2

aEmission factors for kraft calciners are not available. 
8. Proposed Amendments to Table HH-1 to 40 CFR part 98, subpart HH: 

Table HH–1 to Subpart HH of Part 98—Emissions Factors, Oxidation 

Factors and Methods 

Factor Default value Units 

DOC and k values—Bulk waste option

DOC (bulk waste) 0.20 Weight fraction, 

wet basis. 

k (precipitation plus 

recirculated leachatea<20 

inches/year) 

0.02 yr−1 

k (precipitation plus 

recirculated leachatea20–40 

inches/year) 

0.038 yr−1 

k (precipitation plus 

recirculated leachatea>40 

inches/year) 

0.057 yr−1 

DOC and k values—Modified bulk MSW option

DOC (bulk MSW, excluding inerts 

and C&D waste) 

0.31 Weight fraction, 

wet basis. 

DOC (inerts, e.g., glass, 

plastics, metal, concrete) 

0.00 Weight fraction, 

wet basis. 

DOC (C&D waste) 0.08 Weight fraction, 

wet basis. 

k (bulk MSW, excluding inerts 

and C&D waste) 

0.02 to 0.057b yr−1 

k (inerts, e.g., glass, 

plastics, metal, concrete) 

0.00 yr−1 

k (C&D waste) 0.02 to 0.04b yr−1 

DOC and k values—Waste composition option

DOC (food waste) 0.15 Weight fraction, 

wet basis. 

DOC (garden) 0.2 Weight fraction, 
Factor Default value Units 

wet basis. 

DOC (paper) 0.4 Weight fraction, 

wet basis. 

DOC (wood and straw) 0.43 Weight fraction, 

wet basis. 

DOC (textiles) 0.24 Weight fraction, 

wet basis. 

DOC (diapers) 0.24 Weight fraction, 

wet basis. 

DOC (sewage sludge) 0.05 Weight fraction, 

wet basis. 

DOC (inerts, e.g., glass, 

plastics, metal, cement) 

0.00 Weight fraction, 

wet basis. 

k (food waste) 0.06 to 0.185c yr−1 

k (garden) 0.05 to 0.10c yr−1 

k (paper) 0.04 to 0.06c yr−1 

k (wood and straw) 0.02 to 0.03c yr−1 

k (textiles) 0.04 to 0.06c yr−1 

k (diapers) 0.05 to 0.10c yr−1 

k (sewage sludge) 0.06 to 0.185c yr−1 

k (inerts e.g., glass, plastics, 

metal, concrete) 

0.00 yr−1 

Other parameters—All MSW landfills

MCF 1. 

DOCF 0.5 

F 0.5 

OX See Table HH-4 

of this subpart 
Factor Default value Units 

DE 0.99 

aRecirculated leachate (in inches/year) is the total volume of 

leachate recirculated from company records or engineering 

estimates divided by the area of the portion of the landfill 

containing waste with appropriate unit conversions. 

Alternatively, landfills that use leachate recirculation can 

elect to use the k value of 0.057 rather than calculating the 

recirculated leachate rate. 

bUse the lesser value when precipitation plus recirculated 

leachate is less than 20 inches/year. Use the greater value when 

precipitation plus recirculated leachate is greater than 40 

inches/year. Use the average of the range of values when 

precipitation plus recirculated leachate is 20 to 40 inches/year 

(inclusive). Alternatively, landfills that use leachate 

recirculation can elect to use the greater value rather than 

calculating the recirculated leachate rate. 

cUse the lesser value when the potential evapotranspiration rate 

exceeds the mean annual precipitation rate plus recirculated 

leachate. Use the greater value when the potential 

evapotranspiration rate does not exceed the mean annual 

precipitation rate plus recirculated leachate. Alternatively, 

landfills that use leachate recirculation can elect to use the 

greater value rather than assessing the potential 

evapotranspiration rate or recirculated leachate rate. 

9. Proposed Amendments to Table HH-2 to 40 CFR part 98, subpart HH: 

Table HH–2 to Subpart HH of Part 98—U.S. Per Capita Waste 

Disposal Rates

Year 

Waste per capita

ton/cap/yr

1950 0.63 

1951 0.63 

1952 0.63 

1953 0.63 

1954 0.63 

1955 0.63 

1956 0.63 

1957 0.63 

1958 0.63 

1959 0.63 

1960 0.63 

1961 0.64 

1962 0.64 
Year 

Waste per capita

ton/cap/yr

1963 0.65 

1964 0.65 

1965 0.66 

1966 0.66 

1967 0.67 

1968 0.68 

1969 0.68 

1970 0.69 

1971 0.69 

1972 0.70 

1973 0.71 

1974 0.71 

1975 0.72 

1976 0.73 

1977 0.73 

1978 0.74 

1979 0.75 

1980 0.75 

1981 0.76 

1982 0.77 

1983 0.77 

1984 0.78 

1985 0.79 

1986 0.79 

1987 0.80 

1988 0.80 

1989 0.83 

1990 0.82 

1991 0.76 

1992 0.74 

1993 0.76 

1994 0.75 

1995 0.70 

1996 0.68 

1997 0.69 

1998 0.75 

1999 0.75 

2000 0.80 

2001 0.91 

2002 1.02 

2003 1.02 

2004 1.01 

2005 1.060.98 

2006 1.060.95 

2007 0.95 
Year 

Waste per capita

ton/cap/yr

2008 0.95 

2009 and all later years 0.95 

 
10. Proposed Table HH-4 to 40 CFR part 98, subpart HH: 

Table HH–4 to Subpart HH of Part 98—Landfill Methane Oxidation 

Fractions 

If your methane flux ratea for the 

reporting year is: 

Use this landfill methane 

oxidation fraction: 

Less than 10 grams per square 

meter per day (g/m2/d) 

0.35 

10 to 70 g/m2/d 0.25 

Greater than 70 g/m2/d 0.10 

aMethane flux rate (in grams per square meter per day; g/m2/d) is 

the mass flow rate of methane per unit area at the bottom of the 

surface soil prior to any oxidation and is calculated as 

follows. 

For Equation HH-5 of this subpart, or for Equation TT-6 of 

subpart TT of this part, 

MF K G SArea = × CH4

For Equation HH-6 of this subpart, 

MF K G - R SArea

1

CH4 n













= × ∑−

N

n

For Equations HH-7 of this subpart, 

SArea

f

R

CE

1 MF K

1 Rec,n

n

































= × ∑−

N

n

For Equation HH-8 of this subpart, 

R SArea

f

R

CE

1 MF K

1

n

1 Rec,n

n

















−

































= × ∑ ∑ − −

N

n

N

n

Where: 

MF = Methane flux rate from the landfill in the reporting 

year (grams per square meter per day, g/m2/d). 

K = unit conversion factor = 106/365 (g/metric ton per 

days/year) or 106/366 for a leap year. 
SArea = The surface area of the landfill containing waste at 

the beginning of the reporting year (square meters, 

m

2). 

GCH4 = Modeled methane generation rate in reporting year from 

Equation HH–1 of this subpart, or, for application 

with Equation HH-6 only, the greater of the modeled 

methane generation rate in reporting year from 

Equation HH–1 of this subpart and the quantity of 

recovered CH4 from Equation HH–4 of this subpart 

(metric tons CH4). 

CE = Collection efficiency estimated at landfill, taking 

into account system coverage, operation, and cover 

system materials from Table HH–3 of this subpart. If 

area by soil cover type information is not available, 

use default value of 0.75 (CE4 in table HH–3 of this 

subpart) for all areas under active influence of the 

collection system. 

N = Number of landfill gas measurement locations 

(associated with a destruction device or gas sent offsite). If a single monitoring location is used to 

monitor volumetric flow and CH4 concentration of the 

recovered gas sent to one or multiple destruction 

devices, then N=1. 

Rn = Quantity of recovered CH4 from Equation HH–4 of this 

subpart for the nth measurement location (metric tons). 

fRec,n = Fraction of hours the recovery system associated with 

the nth measurement location was operating (annual 

operating hours/8760 hours per year or annual 

operating hours/8784 hours per year for a leap year). 

11. Proposed Amendments to Table MM-1 to 40 CFR part 98, subpart MM: 
Table MM–1 to Subpart MM of Part 98—Default Factors for 

Petroleum Products and Natural Gas Liquids12

Products 

Column A: 

density 

(metric 

tons/bbl) 

Column B:

carbon 

share 

(% of 

mass) 

Column C: 

emission factor

(metric tons 

CO2/bbl) 

Finished Motor Gasoline

Conventional—Summer 

Regular 0.1181 86.66 0.3753 

Midgrade 0.1183 86.63 0.3758 

Premium 0.1185 86.61 0.3763 

Conventional—Winter 

Regular 0.1155 86.50 0.3663 

Midgrade 0.1161 86.55 0.3684 

Premium 0.1167 86.59 0.3705 

Reformulated—Summer 

Regular 0.1167 86.13 0.3686 

Midgrade 0.1165 86.07 0.3677 

Premium 0.1164 86.00 0.3670 

Reformulated—Winter 

Regular 0.1165 86.05 0.3676 

Midgrade 0.1165 86.06 0.3676 

Premium 0.1166 86.06 0.3679 

Gasoline—Other 0.1185 86.61 0.3763 

Blendstocks 

CBOB—Summer 

Regular 0.1181 86.66 0.3753 

Midgrade 0.1183 86.63 0.3758 

Premium 0.1185 86.61 0.3763 

CBOB—Winter 

Regular 0.1155 86.50 0.3663 

Midgrade 0.1161 86.55 0.3684 

Premium 0.1167 86.59 0.3705 
Products 

Column A: 

density 

(metric 

tons/bbl) 

Column B:

carbon 

share 

(% of 

mass) 

Column C: 

emission factor

(metric tons 

CO2/bbl) 

RBOB—Summer 

Regular 0.1167 86.13 0.3686 

Midgrade 0.1165 86.07 0.3677 

Premium 0.1164 86.00 0.3670 

RBOB—Winter 

Regular 0.1165 86.05 0.3676 

Midgrade 0.1165 86.06 0.3676 

Premium 0.1166 86.06 0.3679 

Blendstocks—Other 0.1185 86.61 0.3763 

Oxygenates 

Methanol 0.1268 37.48 0.1743 

GTBA 0.1257 64.82 0.2988 

MTBE 0.1181 68.13 0.2950 

ETBE 0.1182 70.53 0.3057 

TAME 0.1229 70.53 0.3178 

DIPE 0.1156 70.53 0.2990 

Distillate Fuel Oil 

Distillate No. 1 

Ultra Low Sulfur 0.1346 86.40 0.4264 

Low Sulfur 0.1346 86.40 0.4264 

High Sulfur 0.1346 86.40 0.4264 

Distillate No. 2 

Ultra Low Sulfur 0.1342 87.30 0.4296 

Low Sulfur 0.1342 87.30 0.4296 

High Sulfur 0.1342 87.30 0.4296 

Distillate Fuel Oil No. 4 0.1452 86.47 0.4604 

Residual Fuel Oil No. 5 (Navy 

Special) 

0.1365 85.67 0.4288 

Residual Fuel Oil No. 6 0.1528 84.67 0.4744 
Products 

Column A: 

density 

(metric 

tons/bbl) 

Column B:

carbon 

share 

(% of 

mass) 

Column C: 

emission factor

(metric tons 

CO2/bbl) 

(a.k.a. Bunker C) 

Kerosene-Type Jet Fuel 0.1294 86.30 0.4095 

Kerosene 0.1346 86.40 0.4264 

Diesel—Other 0.1452 86.47 0.4604 

Petrochemical Feedstocks 

Naphthas (< 401 °F) 0.1158 84.11 0.3571 

Other Oils (> 401 °F) 0.1390 87.30 0.4450 

Unfinished Oils 

Heavy Gas Oils 0.1476 85.80 0.4643 

Residuum 0.1622 85.70 0.5097 

Other Petroleum Products and Natural Gas Liquids 

Aviation Gasoline 0.1120 85.00 0.3490 

Special Naphthas 0.1222 84.76 0.3798 

Lubricants 0.1428 85.80 0.4492 

Waxes 0.1285 85.30 0.4019 

Petroleum Coke 0.1818 92.28 0.6151 

Asphalt and Road Oil 0.1634 83.47 0.5001 

Still Gas 0.1405 77.70 0.4003 

Ethane3 0.0579 79.89 0.170 

Ethylene4 0.0492 85.63 0.154 

Propane3 0.0806 81.71 0.241 

Propylene3 0.0827 85.63 0.260 

Butane3 0.0928 82.66 0.281 

Butylene3 0.0972 85.63 0.305 

Isobutane3 0.0892 82.66 0.270 

Isobutylene3 0.0949 85.63 0.298 

Pentanes Plus 0.1055 83.63 0.3235 

Miscellaneous Products 0.1380 85.49 0.4326 
1In the case of products blended with some portion of biomassbased fuel, the carbon share in Table MM–1 of this subpart 

represents only the petroleum-based components. 

2Products that are derived entirely from biomass should not be 

reported, but products that were derived from both biomass and a 

petroleum product (i.e., co-processed) should be reported as the 

petroleum product that it most closely represents. 

3The density and emission factors for components of LPG 

determined at 60oF and saturation pressure (LPGs other than 

ethylene) 

4The density and emission factor for ethylene determined at 41oF 

and saturation pressure. 

12. Proposed Amendments to Table NN-1 to 40 CFR part 98, subpart NN: 

Table NN–1 to Subpart NN of Part 98—Default Factors for 

Calculation Methodology 1 of This Subpart 

Fuel Default higher heating value1

Default CO2

emission factor 

(kg CO2/MMBtu) 

Natural Gas 1.026 MMBtu/Mscf 53.06 

Propane 3.84 MMBtu/bbl 62.87 

Normal butane 4.34 MMBtu/bbl 64.77 

Ethane 2.85 MMBtu/bbl 59.60 

Isobutane 4.16 MMBtu/bbl 64.94 

Pentanes plus 4.62 MMBtu/bbl 70.02 

1 Conditions for higher heating values presented in MMBtu/bbl are 60oF and saturation pressure. 

13. Proposed Amendments to Table NN-2 to 40 CFR part 98, subpart NN: 

Table NN–2 to Subpart NN of Part 98—Default Values for 

Calculation Methodology 2 of This Subpart 

Fuel Unit 

Default CO2

emission value 

(MT CO2/Unit) 1

Natural Gas Mscf 0.0544 

Propane Barrel 0.241 

Normal butane Barrel 0.281 

Ethane Barrel 0.170 
Fuel Unit 

Default CO2

emission value 

(MT CO2/Unit) 1

Isobutane Barrel 0.270 

Pentanes plus Barrel 0.324 

1 Conditions for emission value presented in MT CO2/bbl are 60oF and saturation pressure. 

14. Proposed Amendments to Table TT-1 to 40 CFR part 98, subpart TT: 

Table TT–1 to Subpart TT—Default DOC and Decay Rate Values for 

Industrial Waste Landfills 

Industry/Waste Type 

DOC 

(weight 

fraction, 

wet basis) 

k 

[dry 

climatea]

(yr−1) 

k 

[moderate 

climatea] 

(yr−1) 

k 

[wet 

climatea]

(yr−1) 

Food Processing 

(other than sludge) 

0.22 0.06 0.12 0.18 

Pulp and Paper (other 

than sludge) 

0.20 0.02 0.03 0.04 

Wood and Wood Product

(other than sludge) 

0.43 0.02 0.03 0.04 

Construction and 

Demolition 

0.08 0.02 0.03 0.04 

Industrial Sludge 0.09 0.02 0.04 0.06 

Inert Waste [i.e.,

wastes listed in 

§98.460(c)(2)] 

0 0 0 0 

Other Industrial 

Solid Waste (not 

otherwise listed) 

0.20 0.02 0.04 0.06 

aThe applicable climate classification is determined based on the annual 

rainfall plus the recirculated leachate application rate. Recirculated 

leachate application rate (in inches/year) is the total volume of leachate 

recirculated from company records or engineering estimates and applied to the 

landfill divided by the area of the portion of the landfill containing waste 

[with appropriate unit conversions]. 
(1) Dry climate = precipitation plus recirculated leachate 

less than 20 inches/year 

(2) Moderate climate = precipitation plus recirculated 

leachate from 20 to 40 inches/year (inclusive) 

(3) Wet climate = precipitation plus recirculated leachate 

greater than 40 inches/year 

Alternatively, landfills that use leachate recirculation 

can elect to use the k value for wet climate rather than 

calculating the recirculated leachate rate. 

(1) Dry climate = precipitation plus recirculated leachate 

less than 20 inches/year.