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MEMORANDUM

DATE: August 2013

TO: Docket EPA-HQ-OAR-2010-0929

FROM: Lisa Grogan-McCulloch, U.S. EPA

SUBJECT: Amended Sections and Tables of Part 98 – Revisions to Rule Text in Track 

Changes

Attachment A includes all sections and tables of 40 CFR part 98 affected by the proposed 

rulemaking “Revisions to Reporting and Recordkeeping Requirements, and Proposed 

Confidentiality Determinations under the Greenhouse Gas Reporting Program.” The affected 

sections and tables are organized by subpart, and all proposed amendments to the rule text are 

shown in track changes (i.e., redline strikeout format).

The following sections and tables are included:

Subpart A: §98.3, 98.5, Table A-7, Table A-8

Subpart C: §98.36

Subpart E: §98.56

Subpart F: §98.66

Subpart G: §98.76

Subpart H: §98.86

Subpart K: §98.116

Subpart L: §98.126

Subpart N: §98.146

Subpart O: §98.156

Subpart P: §98.166

Subpart Q: §98.176

Subpart R: §98.186

Subpart S: §98.196

Subpart U: §98.216

Subpart V: §98.226

Subpart X: §98.246

Subpart Y: §98.256

Subpart Z: §98.266

Subpart AA: §98.276

Subpart BB: §98.286

Subpart CC: §98.296

Subpart EE: §98.316

Subpart GG: §98.336

Subpart TT: §98.466
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Appendix A

Revisions to Rule Text in Track Changes
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Subpart A- General Provisions

The owner or operator of a facility or supplier that is subject to the requirements of this 

part must submit GHG reports to the Administrator, as specified in this section.

§ 98.3 What are the general monitoring, reporting, recordkeeping and verification requirements 

of this part?

(a) General

(b) 

. Except as provided in paragraph (d) of this section, follow the procedures for 

emission calculation, monitoring, quality assurance, missing data, recordkeeping, and reporting 

that are specified in each relevant subpart of this part.

Schedule

(1) [Reserved]

. The annual GHG report for reporting year 2010 must be submitted no later 

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

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

calendar year. As an example, for a facility or supplier that is subject to the rule in calendar year 

2011, the annual report must be submitted on March 31, 2012.

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

becomes subject to the rule in the year that it becomes operational, report emissions beginning 

with the first operating month and ending on December 31 of that year. Each subsequent annual 

report must cover emissions for the calendar year, beginning on January 1 and ending on 

December 31.

(3) For any facility or supplier that becomes subject to this rule because of a physical or 

operational change that is made after January 1, 2010, report emissions for the first calendar year 

in which the change occurs, beginning with the first month of the change and ending on 

December 31 of that year. For a facility or supplier that becomes subject to this rule solely 

because of an increase in hours of operation or level of production, the first month of the change 
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is the month in which the increased hours of operation or level of production, if maintained for 

the remainder of the year, would cause the facility or supplier to exceed the applicable threshold. 

Each subsequent annual report must cover emissions for the calendar year, beginning on January 

1 and ending on December 31.

(c) Content of the annual report

(1) Facility name or supplier name (as appropriate), and physical street address of the 

facility or supplier, including the city, State, and zip code.

. Except as provided in paragraph (d) of this section, each 

annual GHG report shall contain the following information:

(2) Year and months covered by the report.

(3) Date of submittal.

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

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

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

applicable source categories, expressed in metric tons of CO2e calculated using Equation A–1 of 

this subpart.

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

expressed in metric tons.

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

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

(A) Biogenic CO2.

(B) CO2 (excluding biogenic CO2).

(C) CH4.

(D) N2O.
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(E) Each fluorinated GHG (including those not listed in Table A–1 of this subpart).

(iv) Except as provided in paragraph (c)(4)(vii) of this section, emissions and other data 

for individual units, processes, activities, and operations as specified in the “Data reporting 

requirements” section of each applicable subpart of this part.

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

cogeneration unit located at the facility.

(vi) When applying paragraph (c)(4)(i) of this section to fluorinated GHGs, calculate and 

report CO2e for only those fluorinated GHGs listed in Table A–1 of this subpart.

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

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

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

Table A–7 to this subpart for calendar years 2010 through 2013 until March 31, 2015. Data 

elements specified in Table A-7 to this subpart for calendar years 2010 through 2013 must be 

submitted as part of the annual report for reporting year 2014.

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

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

categories listed in Table A–3 and Table A–4 of this subpart present at the facility.

(5) For suppliers, report annual quantities of CO2,CH4, N2O, and each fluorinated GHG 

(as defined in § 98.6) that would be emitted from combustion or use of the products supplied, 

imported, and exported during the year. Calculate and report quantities at the following levels:

(i) Total quantity of GHG aggregated for all GHG from all applicable supply categories 

in Table A–5 of this subpart and expressed in metric tons of CO2e calculated using Equation A–1 
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of this subpart. For fluorinated GHGs, calculate and report CO2e for only those fluorinated 

GHGs listed in Table A–1 of this subpart.

(ii) Quantity of each GHG from each applicable supply category in Table A–5 of this 

subpart, expressed in metric tons of each GHG. For fluorinated GHG, report emissions of all 

fluorinated GHG, including those not listed in Table A–1 of this subpart. For fluorinated GHGs, 

calculate and report CO2e for only those fluorinated GHGs listed in Table A–1 of this subpart.

(iii) Any other data specified in the “Data reporting requirements” section of each 

applicable subpart of this part.

(6) A written explanation, as required under § 98.3(e), if you change emission calculation 

methodologies during the reporting period.

(7) A brief description of each “best available monitoring method” used according to 

paragraph (d) of this section, the parameter measured using the method, and the time period 

during which the “best available monitoring method” was used, if applicable.

(8) Each data element for which a missing data procedure was used according to the 

procedures of an applicable subpart and the total number of hours in the year that a missing data 

procedure was used for each data element.

(9) A signed and dated certification statement provided by the designated representative 

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

(10) NAICS code(s) that apply to the reporting entity. (i) Primary NAICS code. Report 

the NAICS code that most accurately describes the reporting entity's primary 

product/activity/service. The primary product/activity/service is the principal source of revenue 

for the reporting entity. A reporting entity that has two distinct products/activities/services 

providing comparable revenue may report a second primary NAICS code.
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(ii) Additional NAICS code(s)

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

company(s) of the reporting entity and the percentage of ownership interest for each listed parent 

company as of December 31 of the year for which data are being reported according to the 

following instructions:

. Report all additional NAICS codes that describe all 

product(s)/activity(s)/service(s) at the reporting entity that are not related to the principal source 

of revenue.

(i) If the reporting entity is entirely owned by a single United States company that is not 

owned by another company, provide that company's legal name and physical address as the 

United States parent company and report 100 percent ownership.

(ii) If the reporting entity is entirely owned by a single United States company that is, 

itself, owned by another company (e.g.

(iii) If the reporting entity is owned by more than one United States company (

, it is a division or subsidiary of a higher-level company), 

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

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

e.g.

(iv) If the reporting entity is owned by a joint venture or a cooperative, the joint venture 

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

address of the joint venture or cooperative as the United States parent company, and report 100 

percent ownership by the joint venture or cooperative.

, 

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

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

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

each company.
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(v) If the reporting entity is entirely owned by a foreign company, provide the legal name 

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

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

(vi) If the reporting entity is partially owned by a foreign company and partially owned 

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

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

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

of these companies.

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

and do not report physical address or percent ownership.

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

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

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

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

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

units that 

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

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

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

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

reporting option is chosen, you must report:

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

emissions from part 75 units), aggregated for all applicable source categories.
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(iii) Annual emissions from each applicable source category, expressed in metric tons of 

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

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

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

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

(C) CH4.

(D) N2O.

(E) Each fluorinated GHG (including those not listed in Table A–1 of this subpart).

(d) Special provisions for reporting year 2010.

(1) Best available monitoring methods. During January 1, 2010 through March 31, 2010, 

owners or operators may use best available monitoring methods for any parameter (e.g.

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

of an relevant subpart.

, fuel use, 

daily carbon content of feedstock by process line) that cannot reasonably be measured according 

to the monitoring and QA/QC requirements of a relevant subpart. The owner or operator must 

use the calculation methodologies and equations in the “Calculating GHG Emissions” sections of 

each relevant subpart, but may use the best available monitoring method for any parameter for 

which it is not reasonably feasible to acquire, install, and operate a required piece of monitoring 

equipment by January 1, 2010. Starting no later than April 1, 2010, the owner or operator must 

discontinue using best available methods and begin following all applicable monitoring and 

QA/QC requirements of this part, except as provided in paragraphs (d)(2) and (d)(3) of this 

section. Best available monitoring methods means any of the following methods specified in this 

paragraph:
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(ii) Supplier data.

(iii) Engineering calculations.

(iv) Other company records.

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

(i) 

. The owner or 

operator may submit a request to the Administrator to use one or more best available monitoring 

methods beyond March 31, 2010.

Timing of request

(ii) 

. The extension request must be submitted to EPA no later than 30 

days after the effective date of the GHG reporting rule.

Content of request

(A) A list of specific item of monitoring instrumentation for which the request is being 

made and the locations where each piece of monitoring instrumentation will be installed.

. Requests must contain the following information:

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

paragraph numbers) for which the instrumentation is needed.

(C) A description of the reasons why the needed equipment could not be obtained and 

installed before April 1, 2010.

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

delivered by April 1, 2010, include supporting documentation such as the date the monitoring 

equipment was ordered, investigation of alternative suppliers and the dates by which alternative 

vendors promised delivery, backorder notices or unexpected delays, descriptions of actions taken 

to expedite delivery, and the current expected date of delivery.

(E) If the reason for the extension is that the equipment cannot be installed without a 

process unit shutdown, include supporting documentation demonstrating that it is not practicable 

to isolate the equipment and install the monitoring instrument without a full process unit 
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shutdown. Include the date of the most recent process unit shutdown, the frequency of shutdowns 

for this process unit, and the date of the next planned shutdown during which the monitoring 

equipment can be installed. If there has been a shutdown or if there is a planned process unit 

shutdown between promulgation of this part and April 1, 2010, include a justification of why the 

equipment could not be obtained and installed during that shutdown.

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

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

installed and operating.

(iii) Approval criteria

(3) 

. To obtain approval, the owner or operator must demonstrate to the 

Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a 

required piece of monitoring equipment by April 1, 2010. The use of best available methods will 

not be approved beyond December 31, 2010.

Abbreviated emissions report for facilities containing only general stationary fuel 

combustion sources

(i) Facility name and physical street address including the city, state and zip code.

. In lieu of the report required by paragraph (c) of this section, the owner or 

operator of an existing facility that is in operation on January 1, 2010 and that meets the 

conditions of § 98.2(a)(3) may submit an abbreviated GHG report for the facility for GHGs 

emitted in 2010. The abbreviated report must be submitted by September 30, 2011. An owner or 

operator that submits an abbreviated report must submit a full GHG report according to the 

requirements of paragraph (c) of this section beginning in calendar year 2012. The abbreviated 

facility report must include the following information:

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

(iii) Date of submittal.
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(iv) Total facility GHG emissions aggregated for all stationary fuel combustion units 

calculated according to any method specified in § 98.33(a) and expressed in metric tons of CO2, 

CH4, N2O, and CO2e.

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

98.36(f) of this part, report Aany facility operating data or process information used for the GHG 

emission calculations.

(vi) A signed and dated certification statement provided by the designated representative 

of the owner or operator, according to the requirements of paragraph (e)(1) of this section.

(e) Emission calculations

(f) 

. In preparing the GHG report, you must use the calculation 

methodologies specified in the relevant subparts, except as specified in paragraph (d) of this 

section. For each source category, you must use the same calculation methodology throughout a 

reporting period unless you provide a written explanation of why a change in methodology was 

required.

Verification

(g) 

. To verify the completeness and accuracy of reported GHG emissions, the 

Administrator may review the certification statements described in paragraphs (c)(9) and 

(d)(3)(vi) of this section and any other credible evidence, in conjunction with a comprehensive 

review of the GHG reports and periodic audits of selected reporting facilities. Nothing in this 

section prohibits the Administrator from using additional information to verify the completeness 

and accuracy of the reports.

Recordkeeping. An owner or operator that is required to report GHGs under this part 

must keep records as specified in this paragraph. Retain all required records for at least 3 years. 

Except as otherwise provided in this paragraph, Rretain all required records for at least 3 years 

from the date of submission of the annual GHG report for the reporting year in which the record 
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was generated. The records shall be kept in an electronic or hard-copy format (as appropriate) 

and recorded in a form that is suitable for expeditious inspection and review. If a reporter is 

required under § 98.5(b) to use software specified by the Administrator to enter data to calculate 

the reported GHGs, all records required under Part 98 must be retained by the reporter for 5 

years from the date of submission of the annual GHG report for the reporting year in which the 

record was generated. Upon request by the Administrator, the records required under this section 

must be made available to EPA. Records may be retained off site if the records are readily 

available for expeditious inspection and review. For records that are electronically generated or 

maintained, the equipment or software necessary to read the records shall be made available, or, 

if requested by EPA, electronic records shall be converted to paper documents. You must retain 

the following records, in addition to those records prescribed in each applicable subpart of this 

part:

(1) A list of all units, operations, processes, and activities for which GHG emission were 

calculated.

(2) The data used to calculate the GHG emissions for each unit, operation, process, and 

activity, categorized by fuel or material type. These data include but are not limited to the 

following information in this paragraph (g)(2):

(i) The GHG emissions calculations and methods used. For data required by section 

98.5(b) to be entered into the software specified by the Administrator, maintain the entered data 

in the format generated by the software specified by the Administrator.

(ii) Analytical results for the development of site-specific emissions factors.

(iii) The results of all required analyses for high heat value, carbon content, and other 

required fuel or feedstock parameters.
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(iv) Any facility operating data or process information used for the GHG emission 

calculations.

(3) The annual GHG reports.

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

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

equipment.

(5) A written GHG Monitoring Plan.

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

paragraph (g)(5)(i).

(A) Identification of positions of responsibility (i.e.

(B) Explanation of the processes and methods used to collect the necessary data for the 

GHG calculations.

, job titles) for collection of the 

emissions data.

(C) Description of the procedures and methods that are used for quality assurance, 

maintenance, and repair of all continuous monitoring systems, flow meters, and other 

instrumentation used to provide data for the GHGs reported under this part.

(ii) The GHG Monitoring Plan may rely on references to existing corporate documents 

(e.g.

(iii) The owner or operator shall revise the GHG Monitoring Plan as needed to reflect 

changes in production processes, monitoring instrumentation, and quality assurance procedures; 

, standard operating procedures, quality assurance programs under appendix F to 40 CFR 

part 60 or appendix B to 40 CFR part 75, and other documents) provided that the elements 

required by paragraph (g)(5)(i) of this section are easily recognizable.
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or to improve procedures for the maintenance and repair of monitoring systems to reduce the 

frequency of monitoring equipment downtime.

(iv) Upon request by the Administrator, the owner or operator shall make all information 

that is collected in conformance with the GHG Monitoring Plan available for review during an 

audit. Electronic storage of the information in the plan is permissible, provided that the 

information can be made available in hard copy upon request during an audit.

(6) The results of all required certification and quality assurance tests of continuous 

monitoring systems, fuel flow meters, and other instrumentation used to provide data for the 

GHGs reported under this part.

(7) Maintenance records for all continuous monitoring systems, flow meters, and other 

instrumentation used to provide data for the GHGs reported under this part.

(h) Annual GHG report revisions

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

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

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

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

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

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

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

substantive error.

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

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

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

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

otherwise prevents the reported data from being validated or verified.

(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 business 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.

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

made to an annual GHG report.

(i) Calibration accuracy requirements

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

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

. The owner or operator of a facility or supplier that 

is subject to the requirements of this part must meet the applicable flow meter calibration and 

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

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

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

and/or other parameters. Further, the provisions of this paragraph (i) do not apply to stationary 

fuel combustion units that use the methodologies in part 75 of this chapter to calculate CO2 mass 

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

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

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

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

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

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

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

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

documented in the monitoring plan required under paragraph (g) of this section.

, 

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

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

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

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

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

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

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

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

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

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

(ii) For facilities and suppliers that become subject to this part after April 1, 2010, all 

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

of this part to provide data for the GHG emissions calculations shall be installed no later than the 
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date on which data collection is required to begin using the measurement device, and the initial 

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

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

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

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

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

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

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

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

normal operating range of the meter. Except for the orifice, nozzle, and venturi flow meters 

described in paragraph (i)(3) of this section, calculate the calibration error at each measurement 

point using Equation A–2 of this section. The terms “R” and “A” in Equation A–2 must be 

expressed in consistent units of measure (e.g., gallons/minute, ft3/min). The calibration error at 

each measurement point shall not exceed 5.0 percent of the reference value.

Where:

CE = Calibration error (%).

R = Reference value.

A = Flow meter response to the reference value.

(3) For orifice, nozzle, and venturi flow meters, the initial quality assurance consists of 

in-situ calibration of the differential pressure (delta-P), total pressure, and temperature 

transmitters.

(i) Calibrate each transmitter at a zero point and at least one upscale point. Fixed 

reference points, such as the freezing point of water, may be used for temperature transmitter 
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calibrations. Calculate the calibration error of each transmitter at each measurement point, using 

Equation A–3 of this subpart. The terms “R,” “A,” and “FS” in Equation A–3 of this subpart 

must be in consistent units of measure (e.g., milliamperes, inches of water, psi, degrees). For 

each transmitter, the CE value at each measurement point shall not exceed 2.0 percent of fullscale. Alternatively, the results are acceptable if the sum of the calculated CE values for the three 

transmitters at each calibration level (i.e., at the zero level and at each upscale level) does not 

exceed 6.0 percent.

Where:

CE = Calibration error (%).

R = Reference value.

A = Transmitter response to the reference value.

FS = Full-scale value of the transmitter.

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

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

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

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

each measurement point is still required, in accordance with paragraph (i)(3)(i) of this section; 

alternatively, when two transmitters are calibrated, the results are acceptable if the sum of the CE 

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

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

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

Instead, you may use assumed values for temperature and/or total pressure, based on 
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measurements of these parameters at a remote location (or locations), provided that the following 

conditions are met:

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

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

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

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

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

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

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

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

specification or an industry consensus standard.

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

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

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

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

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

maintain all of this information in a format suitable for auditing and inspection.

(D) You must use the mathematical correlation(s) derived from the demonstration 

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

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

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

measured flow rates to standard conditions.
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(E) You shall periodically check the correlation(s) between the remote and actual 

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

relationship(s).

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

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

and (g)(7) of this section, provided that the fuel supplier and any unit combusting the fuel do not 

have any common owners and are not owned by subsidiaries or affiliates of the same company. 

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

exempted from the calibration requirements of this section.

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

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

(i)(1) of this section if, as of that date, the previous calibration is still active (i.e.

(6) For units and processes that operate continuously with infrequent outages, it may not 

be possible to meet the April 1, 2010 deadline for the initial calibration of a flow meter or other 

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

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

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

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

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

, the device is not 

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

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

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

calibration schedule or you may use the industry consensus calibration schedule.
22

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

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

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

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

period of data invalidation.

(j) 

(1) 

Measurement device installation 

General

(2) 

. If an owner or operator required to report under subpart P, subpart X or 

subpart Y of this part has process equipment or units that operate continuously and it is not 

possible to install a required flow meter or other measurement device by April 1, 2010, (or by 

any later date in 2010 approved by the Administrator as part of an extension of best available 

monitoring methods per paragraph (d) of this section) without process equipment or unit 

shutdown, or through a hot tap, the owner or operator may request an extension from the 

Administrator to delay installing the measurement device until the next scheduled process 

equipment or unit shutdown. If approval for such an extension is granted by the Administrator, 

the owner or operator must use best available monitoring methods during the extension period.

Requests for extension of the use of best available monitoring methods for 

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

initial notification of the intent to submit an extension request for use of best available 

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

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

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

notification with the complete extension request containing the information specified in 

paragraph (j)(4) of this section.
23

(3) Timing of request

(i) The initial notice of intent must be submitted no later than January 1, 2011, or by the 

end of the approved use of best available monitoring methods extension in 2010, whichever is 

earlier. The completed extension request must be submitted to the Administrator no later than 

February 15, 2011.

. 

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

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

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

shutdown that was provided in the original request.

(4) Content of the request

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

where each measurement device will be installed.

. Requests must contain the following information:

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

paragraph numbers) requiring the measurement device.

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

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

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

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

equipment or unit and install the measurement device without a full shutdown or a hot tap, and 

that there was no opportunity during 2010 to install the device. Include the date of the three most 

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

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

unit shutdown.
24

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

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

(5) Approval criteria

(6) 

. The owner or operator must demonstrate to the Administrator's 

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

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

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

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

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

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

method past December 31, 2013.

Measurement device installation deadline

(7) 

. Any owner or operator that submits both a 

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

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

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

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

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

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

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

period, not to extend beyond December 31, 2015. To extend use of best available monitoring 

methods past December 31, 2013, the owner or operator must submit a new extension request by 

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

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

reasonably feasible to install the measurement device before December 31, 2013 without a 
25

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

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

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

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

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

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

(a) Each GHG report and certificate of representation for a facility or supplier must be 

submitted electronically in accordance with the requirements of § 98.4 and in a format specified 

by the Administrator.

§ 98.5 How is the report submitted?

(b) For reporting year 2014 and thereafter, you must enter into verification software 

specified by the Administrator the data used as inputs to the calculation methods specified in 

Table A-8 to Part 98, excluding data required to be reported in the reporting section of each 

subpart listed in Table A-8 to Part 98.

Table A–7 to Subpart A of Part 98—Data Elements That Are Inputs to Emission Equations 

and for Which the Reporting Deadline Is March 31, 2015

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

A 98.3(d)(3)(v) All.

C 98.36(b)(9)(iii) Only estimate of the heat input.1

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

listed in Table C–2.1

C 98.36(e)(2)(i) All.1
26

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

C 98.36(e)(2)(ii)(A) All.1

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

HHV determination is required.1

C 98.36(e)(2)(ii)(D) All.1

C 98.36(e)(2)(iv)(A) All.1

C 98.36(e)(2)(iv)(C) All.1

C 98.36(e)(2)(iv)(F) All.1

C 98.36(e)(2)(ix)(D) All.1

C 98.36(e)(2)(ix)(E) All.1

C 98.36(e)(2)(ix)(F) All.1

E 98.56(b) All.

E 98.56(c) All.

E 98.56(g) All.

E 98.56(h) All.

E 98.56(j)(1) All.

E 98.56(j)(3) All.

E 98.56(j)(4) All.

E 98.56(j)(5) All.

E 98.56(j)(6) All.

E 98.56(l) All.

F 98.66(a) All.

F 98.66(c)(2) All.

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

overvoltage emission factors.

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

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

F 98.66(g) All.

G 98.76(b)(2) All.
27

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

G 98.76(b)(7) All.

G 98.76(b)(8) All.

G 98.76(b)(9) All.

G 98.76(b)(10) All.

G 98.76(b)(11) All.

H 98.86(b)(2) All.

H 98.86(b)(5) All.

H 98.86(b)(6) All.

H 98.86(b)(8) All.

H 98.86(b)(10) All.

H 98.86(b)(11) All.

H 98.86(b)(12) All.

H 98.86(b)(13) All.

H 98.86(b)(1513) Only monthly kiln-specific clinker factors (if used) for 

each kiln.Name of raw kiln feed or raw material.

I 98.96(f)(1) All.

I 98.96(g) Only annual consumption of the gas (excluding annual 

consumption of gases for which the reporter did not 

calculate emissions using Equations I–6, I–7, I–8, I–9, 

and I–10 of subpart L).

I 98.96(h) All.

I 98.96(i) All.

I 98.96(j) All.

I 98.96(k) All.

I 98.96(l) All.

I 98.96(n) All.

I 98.96(o) All.

I 98.96(q)(2) Only inputs and results of calculations made 

accounting for the uptime of abatement systems used 
28

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

during the reporting year.

I 98.96(q)(3) All.

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

I 98.96(r) All.

I 98.96(s) Only estimates of inputs into the heat transfer fluid 

mass balance equation.

K 98.116(b) Only annual production by product from each EAF 

(No CEMS).

K 98.116(e)(4) All.

K 98.116(e)(5) All.

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

data used in calculating the relative errors.

L 98.126(b)(2) All.

L 98.126(b)(6) Only mass of each fluorine-containing reactant fed 

into the process.

L 98.126(b)(8)(i) Only mass of each fluorine-containing product that is 

removed from the process and fed into the destruction 

device.

L 98.126(b)(8)(ii) Only mass of each fluorine-containing by-product that 

is removed from the process and fed into the 

destruction device.

L 98.126(b)(8)(iii) Only mass of each fluorine-containing reactant that is 

removed from the process and fed into the destruction 

device.

L 98.126(b)(8)(iv) Only mass of each fluorine-containing by-product that 

is removed from the process and recaptured.

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

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

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

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

L 98.126(b)(10) All.
29

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

L 98.126(b)(11) All.

L 98.126(b)(12) All.

L 98.126(c)(1) Only quantity of the process activity used to estimate 

emissions.

L 98.126(c)(2) All.

L 98.126(d) Only estimate of missing data.

L 98.126(f)(1) All.

L 98.126(g)(1) All.

L 98.126(h)(2) All.

N 98.146(b)(2) Only annual quantity of carbonate based-raw material 

charged to each continuous glass melting furnace.

N 98.146(b)(4) All.

N 98.146(b)(6) All.

O 98.156(a)(2) All.

O 98.156(a)(7) All.

O 98.156(a)(8) All.

O 98.156(a)(9) All.

O 98.156(a)(10) All.

O 98.156(b)(1) All.

O 98.156(b)(2) All.

O 98.156(d)(1) All.

O 98.156(d)(2) All.

O 98.156(d)(3) All.

O 98.156(d)(4) All.

O 98.156(d)(5) All.

O 98.156(e)(1) All.

P 98.166(b)(2) All.

P 98.166(b)(5) All.
30

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

P 98.166(b)(6) All.

Q 98.176(b) Only annual quantity taconite pellets, coke, iron, and 

raw steel (No CEMS).

Q 98.176(e)(1) All.

Q 98.176(e)(3) All.

Q 98.176(e)(4) All.

Q 98.176(f)(1) All.

Q 98.176(f)(2) All.

Q 98.176(f)(3) All.

Q 98.176(f)(4) All.

Q 98.176(g) All.

R 98.186(b)(6) All.

R 98.186(b)(7) All.

S 98.196(b)(2) All.

S 98.196(b)(3) All.

S 98.196(b)(5) All.

S 98.196(b)(6) All.

S 98.196(b)(8) All.

S 98.196(b)(10) All.

S 98.196(b)(11) All.

S 98.196(b)(12) All.

U 98.216(b) All.

U 98.216(e)(1) All.

U 98.216(e)(2) All.

U 98.216(f)(1) All.

U 98.216(f)(2) All.

V 98.226(c) All.
31

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

V 98.226(d) All.

V 98.226(i) All.

V 98.226(j) All.

V 98.226(m)(1) All.

V 98.226(m)(3) All.

V 98.226(m)(4) All.

V 98.226(m)(5) All.

V 98.226(m)(6) All.

V 98.226(p) All.

W 98.236(c)(1)(i) All.

W 98.236(c)(1)(ii) All.

W 98.236(c)(1)(iii) All.

W 98.236(c)(2)(i) All.

W 98.236(c)(3)(i) All.

W 98.236(c)(3)(ii) All.

W 98.236(c)(3)(iii) All.

W 98.236(c)(4)(i)(A) All.

W 98.236(c)(4)(i)(B) All.

W 98.236(c)(4)(i)(C) All.

W 98.236(c)(4)(i)(D) All.

W 98.236(c)(4)(i)(E) All.

W 98.236(c)(4)(i)(F) All.

W 98.236(c)(4)(i)(G) All.

W 98.236(c)(4)(i)(H) All.

W 98.236(c)(4)(ii)(A) All.

W 98.236(c)(5)(iii) All.

W 98.236(c)(5)(iv) All.
32

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

W 98.236(c)(5)(v) All.

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

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

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

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

W 98.236(c)(6)(ii)(A) All.

W 98.236(c)(6)(ii)(B) All.

W 98.236(c)(7)(i) All.

W 98.236(c)(8)(i)(B) All.

W 98.236(c)(8)(i)(C) All.

W 98.236(c)(8)(i)(F) All.

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

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

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

W 98.236(c)(8)(iii)(D) All.

W 98.236(c)(8)(iii)(E) All.

W 98.236(c)(10)(ii) All.

W 98.236(c)(10)(iii) All.

W 98.236(c)(11)(ii) All.

W 98.236(c)(12)(ii) All.

W 98.236(c)(12)(iii) All.

W 98.236(c)(12)(v) All.

W 98.236(c)(13)(i)(B) All.

W 98.236(c)(13)(i)(E) All.

W 98.236(c)(13)(i)(F) All.

W 98.236(c)(13)(ii)(A) All.

W 98.236(c)(13)(ii)(B) All.
33

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

W 98.236(c)(13)(iii)(A) All.

W 98.236(c)(13)(iii)(B) All.

W 98.236(c)(13)(v)(A) All.

W 98.236(c)(14)(i)(B) All.

W 98.236(c)(14)(ii)(A) All.

W 98.236(c)(14)(ii)(B) All.

W 98.236(c)(14)(iii)(A) All.

W 98.236(c)(14)(iii)(B) All.

W 98.236(c)(14)(v)(A) All.

W 98.236(c)(15)(i)(A) All.

W 98.236(c)(15)(i)(B) All.

W 98.236(c)(15)(ii)(A) All.

W 98.236(c)(15)(ii)(B) All.

W 98.236(c)(16)(i) All.

W 98.236(c)(16)(ii) All.

W 98.236(c)(16)(iii) All.

W 98.236(c)(16)(iv) All.

W 98.236(c)(16)(v) All.

W 98.236(c)(16)(vi) All.

W 98.236(c)(16)(vii) All.

W 98.236(c)(16)(viii) All.

W 98.236(c)(16)(ix) All.

W 98.236(c)(16)(x) All.

W 98.236(c)(16)(xi) All.

W 98.236(c)(16)(xii) All.

W 98.236(c)(16)(xiii) All.

W 98.236(c)(16)(xiv) All.
34

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

W 98.236(c)(17)(ii) All.

W 98.236(c)(17)(iii) All.

W 98.236(c)(17)(iv) All.

W 98.236(c)(18)(i) All.

W 98.236(c)(18)(ii) All.

W 98.236(c)(19)(iv) All.

W 98.236(c)(19)(vii) All.

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

monthly carbon content values, molecular weights for 

gaseous feedstocks, molecular weights for gaseous 

products, and indication of whether the alternative 

method in § 98.243(c)(4) was used.

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

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

Y 98.256(e)(6) Only molar volume conversion factor for each flare.

Y 98.256(e)(7) Only molar volume conversion factor for each flare.

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

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

average higher heating value of the flare gas, volume 

of gas flared, average molecular weight, carbon 

content of the flare, and molar volume conversion 

factor if using Eq. Y–3.

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

methane.

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

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

and average carbon content of coke.

Y 98.256(f)(11) Only units of measure for the unit-specific CH4

emission factor, activity data for calculating 

emissions, and unit-specific emission factor for CH4.

Y 98.256(f)(12) Only unit-specific emission factor for N2O, units of 

measure for the unit-specific N2O emission factor, and 
35

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

activity data for calculating emissions.

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

Y 98.256(h)(4) All.

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

recycled tail gas (if used to calculate recycling 

correction factor), and annual average mole fraction of 

carbon in the tail gas (if used to calculate recycling 

correction factor).

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

green coke fed, annual mass of marketable coke 

produced, carbon content of marketable coke 

produced, and annual mass of coke dust removed from 

the process.

Y 98.256(i)(7) Only the unit-specific CH4 emission factor, units of 

measure for unit-specific CH4 emission factor, and 

activity data for calculating emissions.

Y 98.256(i)(8) Only units of measure for the unit-specific factor, 

activity data used for calculating emissions, and sitespecific emissions factor.

Y 98.256(j)(2) All.

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

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

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

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

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

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

gauge pressure of the coking drum, typical void 

fraction of coke drum or vessel, annual number of 

coke-cutting cycles of coke drum or vessel, and molar 

volume conversion factor for each coke drum or 

vessel.

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

cumulative number of vessel openings for all delayed 

coking drums, typical venting pressure, void fraction, 
36

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

mole fraction of methane in coking gas.

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

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

intermediate products received from off-site, CH4

emission factor used, and molar volume conversion 

factor.

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

from equipment leaks).

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

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

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

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

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

Y 98.256(o)(4)(vi) Only tank-specific methane composition data and gas 

generation rate data.

Y 98.256(o)(6) Only quantity of unstabilized crude oil received 

during the calendar year; average pressure differential; 

and mole fraction of CH4 in vent gas from the 

unstabilized crude oil storage tank.

Y 98.256(o)(7) All.

Y 98.256(p)(2) Only quantity of materials loaded that have an 

equilibrium vapor-phase concentration of CH4 of 0.5 

volume percent or greater.

Z 98.266(f)(5) All.

Z 98.266(f)(6) All.

AA 98.276(b) All.

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

combusted.

AA 98.276(d) All.

AA 98.276(e) All.

AA 98.276(f) All.
37

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

AA 98.276(g) All.

AA 98.276(h) All.

AA 98.276(i) All.

BB 98.286(b)(1) All.

BB 98.286(b)(4) All.

BB 98.286(b)(6) All.

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

feedstock (for facilities using Equation CC–1).

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

manufacturing line(for facilities using Equation CC–

2).

CC 98.296(b)(7) All.

CC 98.296(b)(10)(i) All.

CC 98.296(b)(10)(ii) All.

CC 98.296(b)(10)(iii) All.

CC 98.296(b)(10)(iv) All.

CC 98.296(b)(10)(v) All.

CC 98.296(b)(10)(vi) All.

EE 98.316(b)(6) All.

EE 98.316(b)(9) All.

GG 98.336(b)(6) All.

GG 98.336(b)(7) All.

GG 98.336(b)(10) All.

II 98.356(d)(2) All (if conducting weekly sampling).

II 98.356(d)(3) All (if conducting weekly sampling).

II 98.356(d)(4) Only weekly average temperature (if conducting 

weekly sampling).

II 98.356(d)(5) Only weekly average moisture content (if conducting 

weekly sampling).
38

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which reporting date is 

March 31, 2015 (“All” means all data elements in 

the cited paragraph are not required to be 

reported until March 31, 2015)

II 98.356(d)(6) Only weekly average pressure (if conducting weekly 

sampling).

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

TT 98.466(c)(3)(ii) Only waste disposal quantity and production quantity.

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

1 Required to be reported only by stationary fuel combustion sources (e.g., individual units, 

aggregations of units, common pipes, or common stacks) subject to subpart C of this part that 

meet both of the following criteria: (1) the stationary fuel combustion source contains at least 

one combustion unit connected to a fuel-fired electric generator that has been granted access by 

the Public Utilities Commission to deliver power to the local or regional electric power grid 

(excluding generators that are connected to combustion units subject to subpart D of this part); 

and (2) the stationary fuel combustion source is located at a facility for which the sum of the 

nameplate capacities for all such electric generators is greater than or equal to 1 megawatt 

electric output.

Table A–8 to Subpart A of Part 98—Calculation Methods For Which Inputs To the 

Calculation Methods Must be Entered Into Verification Software Specified By the 

Administrator.

Subpart Calculation Method (Equation Number in 40 CFR Part 98 or Description 

of Method)

Subpart C 1 C-1, C-1a, C-1b, C-2b, C-2c, C-3, C-4, C-5, C-8, C-8a, C-8b, C-10, C-13, the 

calculation method specified in § 98.3(d)(3)(iv) of subpart A

Subpart E E-1, E-2, E-3a, E-3b, E-3c, E-3d 

Subpart F F-2 (including the method for calculating the anode effect minutes per cell-day 

(AEM) and slope coefficients (SCF4), F-3 (including the method for 

calculating the overvoltage factor (EFCF4)), F-5, F-6, F-7, F-8

Subpart G G-1, G-2, G-3

Subpart H H-2 (including the method in § 98.84(d) of subpart H for calculating the 

quantity of clinker produced), H-3, H-4, H-5

Subpart K K-1, K-3

Subpart L L-1, L-2, L-3, L-4, L-6, L-7, L-8, L-17, L-18, L-20, L-21, L-22, L-23, L-25, L26, L-27, L-31, L-34

Subpart N N-1

Subpart O O-3, O-4, O-8, O-9 (including the calculation method specified in § 

98.154(l)(2) of subpart O)

Subpart P P-1, P-2, P-3

Subpart Q Q-1, Q-2, Q-3, Q-4, Q-5, Q-6, Q-7, the calculation methods specified in § 

98.173(b)(2)(iii), (b)(2)(iv), and (c) of subpart Q

Subpart R R-1
39

Subpart Calculation Method (Equation Number in 40 CFR Part 98 or Description 

of Method)

Subpart S S-1, S-2, S-3, S-4 (including the calculation method specified in § 98.194(a)

Subpart U U-1, U-2

Subpart V V-2, V-3a, V-3b, V-3c, V-3d

Subpart X X-1, X-2, X-3, C-8

Subpart Y Y-1a, Y-1b, Y-3, Y-4, Y-6, Y-8, Y-11, Y-12 (including the method for 

correcting the calculation, if applicable, as specified in § 98.253(f)(5)), Y-13, 

Y-14, Y-15, Y-16a, Y-16b, Y-17, Y-18, Y-19, Y-20, Y-22, Y-23, the methods 

for calculating emissions from coke burn-off specified in § 98.253(c)(4) and 

(5) (alternatives to using Equations Y-9 and Y-10 of Part 98), the calculation 

method specified in § 98.253(n) of subpart Y 

Subpart Z Z-1a, Z-1b

Subpart AA C-1, C-1a, C-1b, C-2a, C-3, C-4, C-5, C-8, C-8a, C-8b, C-9a, AA-1, AA-2, 

AA-3

Subpart BB BB-1, BB-2

Subpart CC CC-1, CC-2

Subpart EE EE-2

Subpart GG GG-1

Subpart TT TT-2, TT-3

1 Does not apply to any stationary fuel combustion sources (e.g., individual units, aggregations of 

units, common pipes, or common stacks) subject to subpart C of this part that meet both of the 

following criteria: (1) the stationary fuel combustion source contains at least one combustion unit 

connected to a fuel-fired electric generator that has been granted access by the Public Utilities 

Commission to deliver power to the local or regional electric power grid (excluding generators 

that are connected to combustion units subject to subpart D of this part); and (2) the stationary 

fuel combustion source is located at a facility for which the sum of the nameplate capacities for 

all such electric generators is greater than or equal to 1 megawatt electric output.

Subpart C—General Stationary Fuel Combustion Sources

(a) In addition to the facility-level information required under § 98.3, the annual GHG 

emissions report shall contain the unit-level or process-level emissions data in paragraphs (b) 

through (fd) of this section, (as applicable,) and the emissions verification data in paragraph (e) 

of this section, for each stationary fuel combustion source (e.g., individual unit, aggregation of 

units, common pipe, or common stack).

§ 98.36 Data reporting requirements.
40

(b) Units that use the four tiers

(1) The unit ID number.

. You shall report the following information for stationary 

combustion units that use the Tier 1, Tier 2, Tier 3, or Tier 4 methodology in § 98.33(a) to 

calculate CO2 emissions, except as otherwise provided in paragraphs (c) and (d) of this section:

(2) A code representing the type of unit.

(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 sources.

(4) Each type of fuel combusted in the unit during the report year.

(5) The methodology (i.e., tier) used to calculate the CO2 emissions for each type of fuel 

combusted (i.e.

(6) The methodology start date, for each fuel type.

, Tier 1, 2, 3, or 4).

(7) The methodology end date, for each fuel type.

(8) For a unit that uses Tiers 1, 2, or 3:

(i) The annual CO2 mass emissions (including biogenic CO2), and the annual CH4, and 

N2O mass emissions for each type of fuel combusted during the reporting year, expressed in 

metric tons of each gas and in metric tons of CO2 e; and

(ii) Metric tons of biogenic CO2 emissions (if applicable).

(9) For a unit that uses Tier 4:

(i) If the total annual CO2 mass emissions measured by the CEMS consists entirely of 

non-biogenic CO2 (i.e., CO2 from fossil fuel combustion plus, if applicable, CO2 from sorbent 

and/or process CO2), report the total annual CO2 mass emissions, expressed in metric tons. You 

are not required to report the combustion CO2 emissions by fuel type.
41

(ii) Report the total annual CO2 mass emissions measured by the CEMS. If this total 

includes both biogenic and non-biogenic CO2, separately report the annual non-biogenic CO2

mass emissions and the annual CO2 mass emissions from biomass combustion, each expressed in 

metric tons. You are not required to report the combustion CO2 emissions by fuel type.

(iii) The annual CH4 and N2O emissions for each type of fuel listed in Table C–2 of this 

subpart that was combusted in the unit during the report year, expressed in metric tons of each 

gas and in metric tons of CO2e.

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

paragraph (f) of this section, report Aan estimate of the heat input from each type of fuel listed in 

Table C–2 of this subpart that was combusted in the unit during the report year, and the annual 

CH4 and N2O emissions for each of these fuels, expressed in metric tons of each gas and in 

metric tons of CO2e.

(10) Annual CO2 emissions from sorbent (if calculated using Equation C–11 of this 

subpart), expressed in metric tons.

(c) Reporting alternatives for units using the four Tiers

(1) 

. You may use any of the 

applicable reporting alternatives of this paragraph to simplify the unit-level reporting required 

under paragraph (b) of this section:

Aggregation of units. If a facility contains two or more units (e.g., boilers or 

combustion turbines), each of which has a maximum rated heat input capacity of 250 mmBtu/hr 

or less, you may report the combined GHG emissions for the group of units in lieu of reporting 

GHG emissions from the individual units, provided that the use of Tier 4 is not required or 

elected for any of the units and the units use the same tier for any common fuels combusted. If 
42

this option is selected, the following information shall be reported instead of the information in 

paragraph (b) of this section:

(i) Group ID number, beginning with the prefix “GP”.

(ii) [Reserved]

(iii)[Reserved]

(iv) The highest maximum rated heat input capacity of any unit in the group (mmBtu/hr).

(v) Each type of fuel combusted in the group of units during the reporting year.

(vi) Annual CO2 mass emissions and annual CH4, and N2O mass emissions, aggregated 

for each type of fuel combusted in the group of units during the report year, expressed in metric 

tons of each gas and in metric tons of CO2 e. If any of the units burn both fossil fuels and 

biomass, report also the annual CO2 emissions from combustion of all fossil fuels combined and 

annual CO2 emissions from combustion of all biomass fuels combined, expressed in metric tons.

(vii) The methodology (i.e., tier) used to calculate the CO2 mass emissions for each type 

of fuel combusted in the units (i.e.

(viii) The methodology start date, for each fuel type.

, Tier 1, Tier 2, or Tier 3).

(ix) The methodology end date, for each fuel type.

(x) The calculated CO2 mass emissions (if any) from sorbent expressed in metric tons.

(2) Monitored common stack or duct configurations. When the flue gases from two or 

more stationary fuel combustion units at a facility are combined together in a common stack or 

duct before exiting to the atmosphere and if CEMS are used to continuously monitor CO2 mass 

emissions at the common stack or duct according to the Tier 4 Calculation Methodology, you 

may report the combined emissions from the units sharing the common stack or duct, in lieu of 

separately reporting the GHG emissions from the individual units. This monitoring and reporting 
43

alternative may also be used when process off-gases or a mixture of combustion products and 

process gases are combined together in a common stack or duct before exiting to the atmosphere. 

Whenever the common stack or duct monitoring option is applied, the following information 

shall be reported instead of the information in paragraph (b) of this section:

(i) Common stack or duct identification number, beginning with the prefix “CS”.

(ii) Number of units sharing the common stack or duct. Report “1” when the flue gas 

flowing through the common stack or duct includes combustion products and/or process offgases, and all of the effluent comes from a single unit (e.g.

(iii) Combined maximum rated heat input capacity of the units sharing the common stack 

or duct (mmBtu/hr). This data element is required only when all of the units sharing the common 

stack are stationary fuel combustion units.

, a furnace, kiln, petrochemical 

production unit, or smelter).

(iv) Each type of fuel combusted in the units during the year.

(v) The methodology (tier) used to calculate the CO2 mass emissions, i.e.

(vi) The methodology start date.

, Tier 4.

(vii) The methodology end date.

(viii) Total annual CO2 mass emissions measured by the CEMS, expressed in metric tons. 

If any of the units burn both fossil fuels and biomass, separately report the annual non-biogenic 

CO2 mass emissions (i.e.

(ix) For each type of fuel listed in Table C–2 of this subpart that was combusted during 

the report year in the units sharing the common stack or duct during the report year, the annual 

, CO2 from fossil fuel combustion plus, if applicable, CO2 from sorbent 

and/or process CO2) and the annual CO2 mass emissions from biomass combustion, each 

expressed in metric tons.
44

CH4 and N2O mass emissions from the units sharing the common stack or duct, expressed in 

metric tons of each gas and in metric tons of CO2 e.

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

paragraph (f) of this section, Aan estimate of the heat input from each type of fuel listed in Table 

C–2 of this subpart that was combusted during the report year in the units sharing the common 

stack or duct during the report year, and, for each of these fuels, the annual CH4 and N2O mass 

emissions from the units sharing the common stack or duct, expressed in metric tons of each gas 

and in metric tons of CO2 e.

(3) Common pipe configurations. When two or more stationary combustion units at a 

facility combust the same type of liquid or gaseous fuel and the fuel is fed to the individual units 

through a common supply line or pipe, you may report the combined emissions from the units 

served by the common supply line, in lieu of separately reporting the GHG emissions from the 

individual units, provided that the total amount of fuel combusted by the units is accurately 

measured at the common pipe or supply line using a fuel flow meter, or, for natural gas, the 

amount of fuel combusted may be obtained from gas billing records. For Tier 3 applications, the 

flow meter shall be calibrated in accordance with § 98.34(b). If a portion of the fuel measured (or 

obtained from gas billing records) at the main supply line is diverted to either: A flare; or another 

stationary fuel combustion unit (or units), including units that use a CO2 mass emissions 

calculation method in part 75 of this chapter; or a chemical or industrial process (where it is used 

as a raw material but not combusted), and the remainder of the fuel is distributed to a group of 

combustion units for which you elect to use the common pipe reporting option, you may use 

company records to subtract out the diverted portion of the fuel from the fuel measured (or 

obtained from gas billing records) at the main supply line prior to performing the GHG 
45

emissions calculations for the group of units using the common pipe option. If the diverted 

portion of the fuel is combusted, the GHG emissions from the diverted portion shall be 

accounted for in accordance with the applicable provisions of this part. When the common pipe 

option is selected, the applicable tier shall be used based on the maximum rated heat input 

capacity of the largest unit served by the common pipe configuration, except where the 

applicable tier is based on criteria other than unit size. For example, if the maximum rated heat 

input capacity of the largest unit is greater than 250 mmBtu/hr, Tier 3 will apply, unless the fuel 

transported through the common pipe is natural gas or distillate oil, in which case Tier 2 may be 

used, in accordance with § 98.33(b)(2)(ii). 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. When the common pipe reporting option is selected, the following information shall be 

reported instead of the information in paragraph (b) of this section:

(i) Common pipe identification number, beginning with the prefix “CP”.

(ii) [Reserved]

(iii) The highest maximum rated heat input capacity of any unit served by the common 

pipe (mmBtu/hr).

(iv) The fuels combusted in the units during the reporting year.

(v) The methodology used to calculate the CO2 mass emissions (i.e., Tier 1, Tier 2, or 

Tier 3).

(vi) If the any of the units burns both fossil fuels and biomass, the annual CO2 mass 

emissions from combustion of all fossil fuels and annual CO2 emissions from combustion of all 

biomass fuels from the units served by the common pipe, expressed in metric tons.
46

(vii) Annual CO2 mass emissions and annual CH4 and N2O emissions from each fuel 

type for the units served by the common pipe, expressed in metric tons of each gas and in metric 

tons of CO2 e.

(viii) Methodology start date.

(ix) Methodology end date.

(4) The following alternative reporting option applies to facilities at which a common 

liquid or gaseous fuel supply is shared between one or more large combustion units, such as 

boilers or combustion turbines (including units subject to subpart D of this part and other units 

subject to part 75 of this chapter) and small combustion sources, including, but not limited to, 

space heaters, hot water heaters, and lab burners. In this case, you may simplify reporting by 

attributing all of the GHG emissions from combustion of the shared fuel to the large combustion 

unit(s), provided that:

(i) The total quantity of the fuel combusted during the report year in the units sharing the 

fuel supply is measured, either at the “gate” to the facility or at a point inside the facility, using a 

fuel flow meter, billing meter, or tank drop measurements (as applicable);

(ii) On an annual basis, at least 95 percent (by mass or volume) of the shared fuel is 

combusted in the large combustion unit(s), and the remainder is combusted in the small 

combustion sources. Company records may be used to determine the percentage distribution of 

the shared fuel to the large and small units; and

(iii) The use of this reporting option is documented in the Monitoring Plan required under 

§ 98.3(g)(5). Indicate in the Monitoring Plan which units share the common fuel supply and the 

method used to demonstrate that this alternative reporting option applies. For the small 
47

combustion sources, a description of the types of units and the approximate number of units is 

sufficient.

(d) Units subject to part 75 of this chapter. 

(1) For stationary combustion units that are subject to subpart D of this part, you shall 

report the following unit-level information:

(i) Unit or stack identification numbers. Use exact same unit, common stack, common 

pipe, or multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, 

CS001, MS1A, CP001, etc.

(ii) Annual CO2 emissions at each monitored location, expressed in both short tons and 

metric tons. Separate reporting of biogenic CO2 emissions under § 98.3(c)(4)(ii) and § 

98.3(c)(4)(iii)(A) is optional only for the 2010 reporting year, as provided in § 98.3(c)(12).

) that are reported under §75.64 of this chapter.

(iii) Annual CH4 and N2O emissions at each monitored location, for each fuel type listed 

in Table C–2 that was combusted during the year (except as otherwise provided in § 

98.33(c)(4)(ii)(B)), expressed in metric tons of CO2 e.

(iv) The total heat input from each fuel listed in Table C–2 that was combusted during the 

year (except as otherwise provided in § 98.33(c)(4)(ii)(B)), expressed in mmBtu.

(v) Identification of the Part 75 methodology used to determine the CO2 mass emissions.

(vi) Methodology start date.

(vii) Methodology end date.

(viii) Acid Rain Program indicator.

(ix) Annual CO2 mass emissions from the combustion of biomass, expressed in metric 

tons of CO2 e, except where the reporting provisions of §§ 98.3(c)(12)(i) through (c)(12)(iii) are 

implemented for the 2010 reporting year.
48

(2) For units that use the alternative CO2 mass emissions calculation methods provided in 

§ 98.33(a)(5), you shall report the following unit-level information:

(i) Unit, stack, or pipe ID numbers. Use exact same unit, common stack, common pipe, or 

multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, CS001, 

MS1A, CP001, etc.

(ii) For units that use the alternative methods specified in § 98.33(a)(5)(i) and (ii) to 

monitor and report heat input data year-round according to appendix D to part 75 of this chapter 

or §75.19 of this chapter:

) that are reported under §75.64 of this chapter.

(A) Each type of fuel combusted in the unit during the reporting year.

(B) The methodology used to calculate the CO2 mass emissions for each fuel type.

(C) Methodology start date.

(D) Methodology end date.

(E) A code or flag to indicate whether heat input is calculated according to appendix D to 

part 75 of this chapter or §75.19 of this chapter.

(F) Annual CO2 emissions at each monitored location, across all fuel types, expressed in 

metric tons of CO2 e.

(G) Annual heat input from each type of fuel listed in Table C–2 of this subpart that was 

combusted during the reporting year, expressed in mmBtu.

(H) Annual CH4 and N2O emissions at each monitored location, from each fuel type 

listed in Table C–2 of this subpart that was combusted during the reporting year (except as 

otherwise provided in § 98.33(c)(4)(ii)(D)), expressed in metric tons CO2 e.
49

(I) Annual CO2 mass emissions from the combustion of biomass, expressed in metric tons 

CO2 e, except where the reporting provisions of §§ 98.3(c)(12)(i) through (c)(12)(iii) are 

implemented for the 2010 reporting year.

(iii) For units with continuous monitoring systems that use the alternative method for 

units with continuous monitoring systems in § 98.33(a)(5)(iii) to monitor heat input year-round 

according to part 75 of this chapter:

(A) Each type of fuel combusted during the reporting year.

(B) Methodology used to calculate the CO2 mass emissions.

(C) Methodology start date.

(D) Methodology end date.

(E) A code or flag to indicate that the heat input data is derived from CEMS 

measurements.

(F) The total annual CO2 emissions at each monitored location, expressed in metric tons 

of CO2 e.

(G) Annual heat input from each type of fuel listed in Table C–2 of this subpart that was 

combusted during the reporting year, expressed in mmBtu.

(H) Annual CH4 and N2O emissions at each monitored location, from each fuel type 

listed in Table C–2 of this subpart that was combusted during the reporting year (except as 

otherwise provided in § 98.33(c)(4)(ii)(B)), expressed in metric tons CO2 e.

(I) Annual CO2 mass emissions from the combustion of biomass, expressed in metric tons 

CO2 e, except where the reporting provisions of §§ 98.3(c)(12)(i) through (c)(12)(iii) are 

implemented for the 2010 reporting year.
50

(e) Verification data

(1) The applicable verification data specified in this paragraph (e) are not required to be 

kept on file or reported for units that meet any one of the three following conditions:

. You must keep on file, in a format suitable for inspection and 

auditing, sufficient data to verify the reported GHG emissions. This data and information must, 

where indicated in this paragraph (e), be included in the annual GHG emissions report.

(i) Are subject to the Acid Rain Program.

(ii) Use the alternative methods for units with continuous monitoring systems provided in 

§ 98.33(a)(5).

(iii) Are not in the Acid Rain Program, but are required to monitor and report CO2 mass 

emissions and heat input data year-round, in accordance with part 75 of this chapter.

(2) For stationary combustion sources using the Tier 1, Tier 2, Tier 3, and Tier 4 

Calculation Methodologies in § 98.33(a) to quantify CO2 emissions, the following additional 

information shall be kept on file and included in the GHG emissions report, where indicated:

(i) For the Tier 1 Calculation Methodology, for each stationary fuel combustion source 

that meets the criteria specified in paragraph (f) of this section, report the total quantity of each 

type of fuel combusted in the unit or group of aggregated units (as applicable) during the 

reporting year, in short tons for solid fuels, gallons for liquid fuels and standard cubic feet for 

gaseous fuels, or, if applicable, therms or mmBtu for natural gas.

(ii) For the Tier 2 Calculation Methodology, report:

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

paragraph (f) of this section, Tthe total quantity of each type of fuel combusted in the unit or 

group of aggregated units (as applicable) during each month of the reporting year. Express the 
51

quantity of each fuel combusted during the measurement period in short tons for solid fuels, 

gallons for liquid fuels, and scf for gaseous fuels.

(B) The frequency of the HHV determinations (e.g.

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

paragraph (f) of this section, Tthe high heat values used in the CO2 emissions calculations for 

each type of fuel combusted during the reporting year, in mmBtu per short ton for solid fuels, 

mmBtu per gallon for liquid fuels, and mmBtu per scf for gaseous fuels. Report a HHV value for 

each calendar month in which HHV determination is required. If multiple values are obtained in 

a given month, report the arithmetic average value for the month. Indicate whether each reported 

HHV is a measured value or a substitute data value.

, once a month, once per fuel lot).

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

paragraph (f) of this section, Iif Equation C–2c of this subpart is used to calculate CO2 mass 

emissions, report the total quantity (i.e.

(E) For each HHV used in the CO2 emissions calculations for each type of fuel 

combusted during the reporting year, indicate whether the HHV is a measured value or a 

substitute data value.

, pounds) of steam produced from MSW or solid fuel 

combustion during each month of the reporting year, and the ratio of the maximum rate heat 

input capacity to the design rated steam output capacity of the unit, in mmBtu per lb of steam.

(iii) For the Tier 2 Calculation Methodology, keep records of the methods used to 

determine the HHV for each type of fuel combusted and the date on which each fuel sample was 

taken, except where fuel sampling data are received from the fuel supplier. In that case, keep 

records of the dates on which the results of the fuel analyses for HHV are received.

(iv) For the Tier 3 Calculation Methodology, report:
52

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

paragraph (f) of this section, Tthe quantity of each type of fuel combusted in the unit or group of 

units (as applicable) during each month of the reporting year, in short tons for solid fuels, gallons 

for liquid fuels, and scf for gaseous fuels.

(B) The frequency of carbon content and, if applicable, molecular weight determinations 

for each type of fuel for the reporting year (e.g.

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

paragraph (f) of this section, Tthe carbon content and, if applicable, gas molecular weight values 

used in the emission calculations (including both valid and substitute data values). For each 

calendar month of the reporting year in which carbon content and, if applicable, molecular 

weight determination is required, report a value of each parameter. If multiple values of a 

parameter are obtained in a given month, report the arithmetic average value for the month. 

Express carbon content as a decimal fraction for solid fuels, kg C per gallon for liquid fuels, and 

kg C per kg of fuel for gaseous fuels. Express the gas molecular weights in units of kg per kgmole.

, daily, weekly, monthly, semiannually, once per 

fuel lot).

(D) The total number of valid carbon content determinations and, if applicable, molecular 

weight determinations made during the reporting year, for each fuel type.

(E) The number of substitute data values used for carbon content and, if applicable, 

molecular weight used in the annual GHG emissions calculations.

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

paragraph (f) of this section, Tthe annual average HHV, when measured HHV data, rather than a 
53

default HHV from Table C–1 of this subpart, are used to calculate CH4 and N2O emissions for a 

Tier 3 unit, in accordance with § 98.33(c)(1).

(G) The value of the molar volume constant (MVC) used in Equation C–5 (if applicable).

(v) For the Tier 3 Calculation Methodology, keep records of the following:

(A) For liquid and gaseous fuel combustion, the dates and results of the initial 

calibrations and periodic recalibrations of the required fuel flow meters.

(B) For fuel oil combustion, the method from § 98.34(b) used to make tank drop 

measurements (if applicable).

(C) The methods used to determine the carbon content and (if applicable) the molecular 

weight of each type of fuel combusted.

(D) The methods used to calibrate the fuel flow meters).

(E) The date on which each fuel sample was taken, except where fuel sampling data are 

received from the fuel supplier. In that case, keep records of the dates on which the results of the 

fuel analyses for carbon content and (if applicable) molecular weight are received.

(vi) For the Tier 4 Calculation Methodology, report:

(A) The total number of source operating hours in the reporting year.

(B) The cumulative CO2 mass emissions in each quarter of the reporting year, i.e., the 

sum of the hourly values calculated from Equation C–6 or C–7 of this subpart (as applicable), in 

metric tons.

(C) For CO2 concentration, stack gas flow rate, and (if applicable) stack gas moisture 

content, the percentage of source operating hours in which a substitute data value of each 

parameter was used in the emissions calculations.

(vii) For the Tier 4 Calculation Methodology, keep records of:
54

(A) Whether the CEMS certification and quality assurance procedures of part 75 of this 

chapter, part 60 of this chapter, or an applicable State continuous monitoring program were used.

(B) The dates and results of the initial certification tests of the CEMS.

(C) The dates and results of the major quality assurance tests performed on the CEMS 

during the reporting year, i.e., linearity checks, cylinder gas audits, and relative accuracy test 

audits (RATAs).

(viii) If CO2 emissions that are generated from acid gas scrubbing with sorbent injection 

are not captured using CEMS, report:

(A) The total amount of sorbent used during the report year, in short tons.

(B) The molecular weight of the sorbent.

(C) The ratio (“R”) in Equation C–11 of this subpart.

(ix) For units that combust both fossil fuel and biomass, when biogenic CO2 is 

determined according to § 98.33(e)(2), you shall report the following additional information, as 

applicable:

(A) The annual volume of CO2 emitted from the combustion of all fuels, i.e.

(B) The annual volume of CO2 emitted from the combustion of fossil fuels, 

, Vtotal, in scf.

i.e.

(C) The annual volume of CO2 emitted from the combustion of biomass, 

, Vff, in 

scf. If more than one type of fossil fuel was combusted, report the combustion volume of CO2 for 

each fuel separately as well as the total.

i.e.

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

paragraph (f) of this section, Tthe carbon-based F-factor used in Equation C–13 of this subpart, 

for each type of fossil fuel combusted, in scf CO2 per mmBtu.

, Vbio, in scf.
55

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

paragraph (f) of this section, Tthe annual average HHV value used in Equation C–13 of this 

subpart, for each type of fossil fuel combusted, in Btu/lb, Btu/gal, or Btu/scf, as appropriate.

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

paragraph (f) of this section, Tthe total quantity of each type of fossil fuel combusted during the 

reporting year, in lb, gallons, or scf, as appropriate.

(G) Annual biogenic CO2 mass emissions, in metric tons.

(x) When ASTM methods D7459–08 (incorporated by reference, see § 98.7) and D6866–

08 (incorporated by reference, see § 98.7) are used to determine the biogenic portion of the 

annual CO2 emissions from MSW combustion, as described in § 98.34(d), report:

(A) The results of each quarterly sample analysis, expressed as a decimal fraction (e.g.

(B) The annual biogenic CO2 mass emissions from MSW combustion, in metric tons.

, if 

the biogenic fraction of the CO2 emissions from MSW combustion is 30 percent, report 0.30).

(xi) When ASTM methods D7459–08 (incorporated by reference, see § 98.7) and

D6866–08 (incorporated by reference, see § 98.7) are used in accordance with § 98.34(e) to 

determine the biogenic portion of the annual CO2 emissions from a unit that co-fires biogenic 

fuels (or partly-biogenic fuels, including tires if you are electing to report biogenic CO2

emissions from tire combustion) and non-biogenic fuels, you shall report the results of each 

quarterly sample analysis, expressed as a decimal fraction (e.g.

(3) Within 30 days of receipt of a written request from the Administrator, you shall 

submit explanations of the following:

, if the biogenic fraction of the 

CO2 emissions is 30 percent, report 0.30).
56

(i) An explanation of how company records are used to quantify fuel consumption, if the 

Tier 1 or Tier 2 Calculation Methodology is used to calculate CO2 emissions.

(ii) An explanation of how company records are used to quantify fuel consumption, if 

solid fuel is combusted and the Tier 3 Calculation Methodology is used to calculate CO2

emissions.

(iii) An explanation of how sorbent usage is quantified.

(iv) An explanation of how company records are used to quantify fossil fuel consumption 

in units that uses CEMS to quantify CO2 emissions and combusts both fossil fuel and biomass.

(v) An explanation of how company records are used to measure steam production, when 

it is used to calculate CO2 mass emissions under § 98.33(a)(2)(iii) or to quantify solid fuel usage 

under § 98.33(c)(3).

(4) Within 30 days of receipt of a written request from the Administrator, you shall 

submit the verification data and information described in paragraphs (e)(2)(iii), (e)(2)(v), and 

(e)(2)(vii) of this section.

(f) Each stationary fuel combustion source (e.g., individual unit, aggregation of units, 

common pipe, or common stack) subject to reporting under paragraph (b), (c), or (d)(2) of this 

section must indicate if both of the following two conditions are met:

(1) The stationary combustion source contains at least one combustion unit connected to 

a fuel-fired electric generator that has been granted access by the Public Utilities Commission to 

deliver power to the local or regional electric power grid (excluding generators that are 

connected to combustion units that are subject to subpart D of this part).
57

(2) The stationary fuel combustion source is located at a facility for which the sum of the 

nameplate capacities for all electric generators specified in paragraph (f)(1) of this section is 

greater than or equal to 1 megawatt electric output.

Subpart E—Adipic Acid Production

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) through (ln) of this section at the facility level.

§ 98.56 Data reporting requirements.

(a) Annual process N2O emissions from adipic acid production (metric tons).

(b) [Reserved]Annual adipic acid production (tons).

(c) [Reserved]Annual adipic acid production during which N2O abatement technology 

(located after the test point) is operating (tons).

(d) Annual process N2O emissions from adipic acid production facility that is sold or 

transferred off site (metric tons).

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

(f) Types of abatement technologies used (if applicable).

(g) Abatement technology destruction efficiency for each abatement technology (percent 

destruction).

(h) Abatement utilization factor for each abatement technology (fraction of annual 

production that abatement technology is operating).

(i) Number of times in the reporting year that missing data procedures were followed to 

measure adipic acid production (months).

(j) If you conducted a performance test and calculated a site-specific emissions factor 

according to § 98.53(a)(1), each annual report must also contain the information specified in 

paragraphs (j)(1) through (7) of this section for each adipic acid production unit.
58

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

(2) Test method used for performance test.

(3) [Reserved]Production rate per test run during performance test (tons/hr).

(4) N2O concentration per test run during performance test (ppm N2O).

(5) Volumetric flow rate per test run during performance test (dscf/hr).

(6) Number of test runs.

(7) Number of times in the reporting year that a performance test had to be repeated 

(number).

(k) If you requested Administrator approval for an alternative method of determining 

N2O emissions under § 98.53(a)(2), each annual report must also contain the information 

specified in paragraphs (k)(1) through (4) of this section for each adipic acid production facility.

(1) Name of alternative method.

(2) Description of alternative method.

(3) Request date.

(4) Approval date.

(l) Fraction control factor for each abatement technology (percent of total emissions from 

the production unit that are sent to the abatement technology) if equation E–3c is used.

(m) Annual quantity of cyclohexane fed to all production lines combined (metric tons).

(n) Annual percent N2O emission reduction for all production units combined.

Subpart F—Aluminum Production

In addition to the information required by § 98.3(c), you must report the following 

information at the facility level:

§ 98.66 Data reporting requirements.

(a) [Reserved]Annual aluminum production in metric tons.
59

(b) Type of smelter technology used.

(c) The following PFC-specific information on an annual basis:

(1) Perfluoromethane emissions and perfluoroethane emissions from anode effects in all 

prebake and all Sderberg electrolysis cells combined.

(2) [Reserved]Anode effect minutes per cell-day (AE-mins/cell-day), anode effect 

frequency (AE/cell-day), anode effect duration (minutes). (Or anode effect overvoltage factor 

((kg CF4/metric ton Al)/(mV/cell day)), potline overvoltage (mV/cell day), current efficiency 

(%).)

(3) Smelter-specific slope coefficients (or overvoltage emission factors) and tThe last 

date when the smelter-specific-slope coefficients (or overvoltage emission factors) were 

measured.

(d) Method used to measure the frequency and duration of anode effects (or overvoltage).

(e) The following CO2 -specific information for prebake cells:

(1) Annual anode consumption if using the method in § 98.63(g).

(2) Annual CO2 emissions from the smelter.

(f) The following CO2 -specific information for Sderberg cells:

(1) Annual paste consumption if using the method in § 98.63(g).

(2) Annual CO2 emissions from the smelter.

(g) [Reserved]Smelter-specific inputs to the CO2 process equations (e.g.

(h) Exact data elements required will vary depending on smelter technology (

, levels of sulfur 

and ash) that were used in the calculation, on an annual basis.

e.g., pointfeed prebake or Sderberg) and process control technology (e.g.

Subpart G—Ammonia Manufacturing

, Pechiney or other).

§ 98.76 Data reporting requirements.
60

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) and (b) of this section, as applicable for each ammonia 

manufacturing process unit.

(a) If a CEMS is used to measure CO2 emissions, then you must report the relevant 

information required under § 98.36 for the Tier 4 Calculation Methodology and the following 

information in this paragraph (a):

(1) Annual quantity of each type of feedstock consumed for ammonia manufacturing (scf 

of feedstock or gallons of feedstock or kg of feedstock).

(2) Method used for determining quantity of feedstock used.

(b) If a CEMS is not used to measure emissions, then you must report the following 

information:

(1) Annual CO2 process emissions (metric tons) for each ammonia manufacturing process 

unit.

(2) [Reserved]Monthly quantity of each type of feedstock consumed for ammonia 

manufacturing for each ammonia processing unit (scf of feedstock or gallons of feedstock or kg 

of feedstock).

(3) Method used for determining quantity of monthly feedstock used.

(4) Whether carbon content for each feedstock for month n is based on reports from the 

supplier or analysis of carbon content.

(5) If carbon content of feedstock for month n is based on analysis, the test method used.

(6) Sampling analysis results of carbon content of feedstock as determined for QA/QC of 

supplier data under § 98.74(e).
61

(7) [Reserved]If a facility uses gaseous feedstock, the carbon content of the gaseous 

feedstock, for month n, (kg C per kg of feedstock).

(8) [Reserved]If a facility uses gaseous feedstock, the molecular weight of the gaseous 

feedstock (kg/kg-mole).

(9) [Reserved]If a facility uses gaseous feedstock, the molar volume conversion factor of 

the gaseous feedstock (scf per kg-mole).

(10) [Reserved]If a facility uses liquid feedstock, the carbon content of the liquid 

feedstock, for month n, (kg C per gallon of feedstock).

(11) [Reserved]If a facility uses solid feedstock, the carbon content of the solid feedstock, 

for month n, (kg C per kg of feedstock).

(12) Annual urea production (metric tons) and method used to determine urea production.

(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.

(14) Annual ammonia production (metric tons).

(15) Annual methanol production (metric tons), if this quantity is not reported under 

subpart X of this part.

Subpart H—Cement Production

In addition to the information required by § 98.3(c), each annual report must contain the 

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

§ 98.86 Data reporting requirements.

(a) If a CEMS is used to measure CO2 emissions, then you must report under this subpart 

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

paragraph(a):
62

(1) Monthly clinker production from each kiln at the facility.

(2) Monthly cement production from each kiln at the facility.

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

(b) If a CEMS is not used to measure CO2 emissions, then you must report the 

information listed in this paragraph (b) for each kiln:

(1) Kiln identification number.

(2) [Reserved]Monthly clinker production from each kiln.

(3) Annual cement production at the facility.

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

(5) [Reserved]Quarterly quantity of CKD not recycled to the kiln for each kiln at the 

facility.

(6) [Reserved]Monthly fraction of total CaO, total MgO, non-calcined CaO and noncalcined MgO in clinker for each kiln (as wt-fractions).

(7) Method used to determine non-calcined CaO and non-calcined MgO in clinker.

(8) [Reserved]Quarterly fraction of total CaO, total MgO, non-calcined CaO and noncalcined MgO in CKD not recycled to the kiln for each kiln (as wt-fractions).

(9) Method used to determine non-calcined CaO and non-calcined MgO in CKD.

(10) [Reserved]Monthly kiln-specific clinker CO2 emission factors for each kiln (metric 

tons CO2/metric ton clinker produced).

(11) Quarterly kiln-specific CKD CO2 emission factors for each kiln (metric tons 

CO2/metric ton CKD produced).

(12) [Reserved]Annual organic carbon content of raw kiln feed or annual organic carbon 

content of each raw material (wt-fraction, dry basis).
63

(13) Name ofAnnual consumption of raw kiln feed or annual consumption of each raw 

material(dry basis).

(14) Number of times missing data procedures were used to determine the following 

information:

(i) Clinker production (number of months).

(ii) Carbonate contents of clinker (number of months).

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

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

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

(vi) Organic carbon contents of raw materials (number of times).

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

(15) Method used to determine the monthly clinker production from each kiln reported 

under (b)(2) of this section, including monthly kiln-specific clinker factors, if used.

(16) Annual clinker production (metric tons).

(17) Annual average clinker CO2 emission factor for the facility, averaged across all kilns 

(metric tons CO2/metric ton clinker produced).

(18) Annual average CKD CO2 emission factor for the facility, averaged across all kilns 

(metric tons CO2/metric ton CKD produced).

Subpart K—Ferroalloy Production

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) through (e) of this section, as applicable:

§ 98.116 Data reporting requirements.

(a) Annual facility ferroalloy product production capacity (tons).
64

(b) [Reserved]Annual production for each ferroalloy product identified in § 98.110, from 

each EAF (tons).

(c) Total number of EAFs at facility used for production of ferroalloy products.

(d) If a CEMS is used to measure CO2 emissions, then you must report under this subpart 

the relevant information required by § 98.36 for the Tier 4 Calculation Methodology and the 

following information specified in paragraphs (d)(1) through (d)(3) of this section.

(1) Annual process CO2 emissions (in metric tons) from each EAF used for the 

production of any ferroalloy product identified in § 98.110.

(2) Annual process CH4 emissions (in metric tons) from each EAF used for the 

production of any ferroalloy listed in Table K–1 of this subpart (metric tons).

(3) Identification number of each EAF.

(e) If a CEMS is not used to measure CO2 process emissions, and the carbon mass 

balance procedure is used to determine CO2 emissions according to the requirements in § 

98.113(b), then you must report the following information specified in paragraphs (e)(1) through 

(e)(7) of this section.

(1) Annual process CO2 emissions (in metric tons) from each EAF used for the 

production of any ferroalloy identified in § 98.110 (metric tons).

(3) Identification number for each material.

(4) [Reserved]Annual material quantity for each material included for the calculation of 

annual process CO2 emissions for each EAF.

(5) [Reserved]Annual average of the carbon content determinations for each material 

included for the calculation of annual process CO2 emissions for each EAF (percent by weight, 

expressed as a decimal fraction).
65

(6) List the method used for the determination of carbon content for each material 

reported in paragraph (e)(5) of this sectionincluded for the calculation of annual process CO2

emissions for each EAF (e.g.

(7) If you use the missing data procedures in § 98.115(b), you must report how monthly 

mass of carbon-containing inputs and outputs with missing data was determined and the number 

of months the missing data procedures were used.

, supplier provided information, analyses of representative samples 

you collected).

Subpart L—Fluorinated Gas Production

(a) 

§ 98.126 Data reporting requirements.

All facilities

(1) 

. In addition to the information required by § 98.3(c), you must report the 

information in paragraphs (a)(2) through (a)(6) of this section according to the schedule in 

paragraph (a)(1) of this section, except as otherwise provided in paragraph (j) of this section or in 

§ 98.3(c)(4)(vii) and Table A–7 of Subpart A of this part.

Frequency of reporting under paragraph (a) of this section

(2) You must report the total mass in metric tons of each fluorinated GHG emitted from:

. The information in 

paragraphs (a)(2), (5), and (6) of this section must be reported annually. The information in 

paragraphs (a)(3) and (4) of this section must be reported once by March 31, 2012 for each 

process and operating scenarios that operates between December 31, 2010 and December 31, 

2011. For other processes and operating scenarios, the information in paragraphs (a)(3) and (4) 

of this section must be reported once by March 31 of the year following the year in which the 

process or operating scenario commences or recommences.

(i) Each fluorinated gas production process and all fluorinated gas production processes 

combined.
66

(ii) Each fluorinated gas transformation process that is not part of a fluorinated gas 

production process and all such fluorinated gas transformation processes combined, except report 

separately fluorinated GHG emissions from transformation processes where a fluorinated GHG 

reactant is produced at another facility.

(iii) Each fluorinated gas destruction process that is not part of a fluorinated gas 

production process or a fluorinated gas transformation process and all such fluorinated gas 

destruction processes combined.

(iv) Venting of residual fluorinated GHGs from containers returned from the field.

(3) The chemical identities of the contents of the stream(s) (including process, emissions, 

and destroyed streams) analyzed under the initial scoping speciation of fluorinated GHG at § 

98.124(a), by process.

(4) The location and function of the stream(s) (including process streams, emissions 

streams, and destroyed streams) that were analyzed under the initial scoping speciation of 

fluorinated GHG at § 98.124(a), by process.

(5) The method used to determine the mass emissions of each fluorinated GHG, i.e.

(6) The chemical formula and total mass produced of the fluorinated gas product in 

metric tons, by chemical and process.

, mass 

balance, process-vent-specific emission factor, or process-vent-specific emission calculation 

factor, at the facility. If you use the process-vent-specific emission factor or process-ventspecific emission calculation factor method, report the methods used to estimate emissions from 

equipment leaks.

(b) Reporting for mass balance approach. For processes whose emissions are determined 

using the mass-balance approach under § 98.123(b), you must report the information listed in 
67

paragraphs (b)(1) through (b)(13) of this section for each process on an annual basis. Identify and 

separately report fluorinated GHG emissions from transformation processes where the 

fluorinated GHG reactants are produced at another facility. If you use an element other than 

fluorine in the mass-balance equation pursuant to § 98.123(b)(3), substitute that element for 

fluorine in the reporting requirements of this paragraph.

(1) If you calculate the relative and absolute errors under 98.123(b)(1), the absolute and 

relative errors calculated under paragraph § 98.123(b)(1), as well as the data (including 

quantities and their accuracies and precisions) used in these calculations.

(2) [Reserved]The balanced chemical equation that describes the reaction used to 

manufacture the fluorinated GHG product and each fluorinated GHG transformation product.

(3) The mass and chemical formula of each fluorinated GHG reactant emitted from the 

process in metric tons.

(4) The mass and chemical formula of the fluorinated GHG product emitted from the 

process in metric tons.

(5) The mass and chemical formula of each fluorinated GHG by-product emitted from the 

process in metric tons.

(6) The mass and chemical formula of each fluorine-containing reactant that is fed into 

the process (metric tons).

(7) The mass and chemical formula of each fluorine-containing product produced by the 

process (metric tons).

(8) If you use § 98.123(b)(4) to estimate the total mass of fluorine in destroyed or 

recaptured streams, report the following.
68

(i) The mass and chemical formula of each fluorine-containing product that is removed 

from the process and fed into the destruction device (metric tons).

(ii) The mass and chemical formula of each fluorine-containing by-product that is 

removed from the process and fed into the destruction device (metric tons).

(iii) The mass and chemical formula of each fluorine-containing reactant that is removed 

from the process and fed into the destruction device (metric tons).

(iv) The mass and chemical formula of each fluorine-containing by-product that is 

removed from the process and recaptured (metric tons).

(v) [Reserved]The demonstrated destruction efficiency of the destruction device for each 

fluorinated GHG fed into the device from the process in greater than trace concentrations 

(fraction).

(9) [Reserved]If you use § 98.123(b)(15) to estimate the total mass of fluorine in 

destroyed or recaptured streams, report the following.

(i) The mass of fluorine in each stream that is fed into the destruction device (metric 

tons).

(ii) The mass of fluorine that is recaptured (metric tons).

(iii) The weighted average destruction efficiency of the destruction device calculated for 

each stream under § 98.123(b)(16).

(10) The fraction of the mass emitted that consists of each fluorine-containing reactant.

(11) The fraction of the mass emitted that consists of the fluorine-containing product.

(12) The fraction of the mass emitted that consists of each fluorine-containing byproduct.
69

(13) The method used to estimate the total mass of fluorine in destroyed or recaptured 

streams (specify § 98.123(b)(4) or (15)).

(c) Reporting for emission factor and emission calculation factor approach

(1) The identity and quantity of the process activity used to estimate emissions (

. For processes 

whose emissions are determined using the emission factor approach under § 98.123(c)(3) or the 

emission calculation factor under § 98.123(c)(4), you must report the following for each process. 

Fluorinated GHG emissions from transformation processes where the fluorinated GHG reactants 

are produced at another facility must be identified and reported separately from other fluorinated 

GHG emissions.

e.g.

(2) [Reserved]The site-specific, process-vent-specific emission factor(s) or emission 

calculation factor for each process vent.

, tons 

of product produced or tons of reactant consumed).

(3) The mass of each fluorinated GHG emitted from each process vent (metric tons).

(4) The mass of each fluorinated GHG emitted from equipment leaks (metric tons).

(d) Reporting for missing data

(1) tThe reason the data were missing, the length of time the data were missing, and the 

method used to estimate the missing data, and the estimates of those data.

. Where missing data have been estimated pursuant to §

98.125, you must report:

(2) Estimates of the missing data for all missing data associated with data elements 

required to be reported in this section.

(e) Reporting of destruction device excess emissions data. Each fluorinated gas 

production facility that destroys fluorinated GHGs must report the excess emissions that result 

from malfunctions of the destruction device, and these excess emissions would be reflected in 
70

the fluorinated GHG estimates in § 98.123(b) and (c). Such excess emissions would occur if the 

destruction efficiency was reduced due to the malfunction.

(f) Reporting of destruction device testing

(1) [Reserved]Destruction efficiency (DE) of each destruction device for each fluorinated 

GHG whose destruction the facility reflects in § 98.123, in accordance with § 98.124(g)(1)(i) 

through (iv).

. By March 31, 2012 or by March 31 of the 

year immediately following the year in which it begins fluorinated GHG destruction, each 

fluorinated gas production facility that destroys fluorinated GHGs must submit a report 

containing the information in paragraphs (f)(1) through (f)(4) of this section. This report is onetime unless you make a change to the destruction device that would be expected to affect its 

destruction efficiencies.

(2) Chemical identity of the fluorinated GHG(s) used in the performance test conducted 

to determine destruction efficiency, including surrogates, and information on why the surrogate 

is sufficient to demonstrate the destruction efficiency for each fluorinated GHG, consistent with 

requirements in § 98.124(g)(1), vented to the destruction device.

(3) Date of the most recent destruction device test.

(4) Name of all applicable Federal or State regulations that may apply to the destruction 

process.

(5) If you make a change to the destruction device that would be expected to affect its 

destruction efficiencies, submit a revised report that reflects the changes, including the revised 

destruction efficiencies measured for the device under § 98.124(g)(2)(ii), by March 31 of the 

year that immediately follows the change.
71

(g) Reporting for destruction of previously produced fluorinated GHGs

(1) [Reserved]The mass of the fluorinated GHG fed into the destruction device.

. Each fluorinated 

gas production facility that destroys fluorinated GHGs must report, separately from the 

fluorinated GHG emissions reported under paragraphs (b) or (c) of this section, the following for 

each previously produced fluorinated GHG destroyed:

(2) The mass of the fluorinated GHG emitted from the destruction device.

(h) Reporting of emissions from venting of residual fluorinated GHGs from containers

(1) The mass of the residual fluorinated GHG vented from each container size and type 

annually (tons).

. 

Each fluorinated gas production facility that vents residual fluorinated GHGs from containers 

must report the following for each fluorinated GHG vented:

(2) [Reserved]If applicable, the heel factor calculated for each container size and type.

(i) Reporting of fluorinated GHG products of incomplete combustion (PICs) of 

fluorinated gases. Each fluorinated gas production facility that destroys fluorinated gases must 

submit a one-time report by June 30, 2011, that describes any measurements, research, or 

analysis that it has performed or obtained that relate to the formation of products of incomplete 

combustion that are fluorinated GHGs during the destruction of fluorinated gases. The report 

must include the methods and results of any measurement or modeling studies, including the 

products of incomplete combustion for which the exhaust stream was analyzed, as well as copies 

of relevant scientific papers, if available, or citations of the papers, if they are not. No new 

testing is required to fulfill this requirement.
72

(j) Special provisions for reporting years 2011 and 2012 only

(1) 

. 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.

Timing

(2) 

. 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.

Excess emissions

(3) 

. Excess emissions of fluorinated GHGs resulting from destruction 

device malfunctions must be reflected in the reported facility-wide CO2 e emissions but are not 

required to be reported separately.

Calculation and reporting of CO2e. You must report the total fluorinated GHG 

emissions covered by this subpart, expressed in metric tons of CO2 e. This includes emissions 

from all fluorinated gas production processes, all fluorinated gas transformation processes that 

are not part of a fluorinated gas production process, all fluorinated gas destruction processes that 

are not part of a fluorinated gas production process or a fluorinated gas transformation process, 

and venting of residual fluorinated GHGs from containers returned from the field. To convert 

fluorinated GHG emissions to CO2 e for reporting under this section, use Equation A-1 of § 98.2. 

For fluorinated GHGs whose GWPs are not listed in Table A-1 of Subpart A of this part, use 

either the default GWP specified below or your best estimate of the GWP based on the 

information described in § 98.123(c)(1)(vi)(A)( 3 ). Use of quantitative structure activity 

relationships (QSARs) is an acceptable method for determining GWPs in situations where pure 

standards of the “target” fluorinated GHG are not available, the “target” fluorinated GHG cannot 

be isolated from gas streams, and FTIR spectra for the impurities are not available.
73

(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.

(ii) Provide the total annual emissions across fluorinated GHGs for the entire facility, in 

metric tons of CO2 e, that were calculated using the default GWP of 2000.

(iii) Provide the total annual emissions across fluorinated GHGs for the entire facility, in 

metric tons of CO2 e, that were calculated using the default GWP of 10,000.

(iv) Provide the total annual emissions across fluorinated GHGs for the entire facility, in 

metric tons of CO2e, that were calculated using your best estimate of the GWP.

Subpart N—Glass Production

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) and (b) of this section, as applicable.

§ 98.146 Data reporting requirements.

(a) If a CEMS is used to measure CO2 emissions, then you must report under this subpart 

the relevant information required under § 98.36 for the Tier 4 Calculation Methodology and the 

following information specified in paragraphs (a)(1) and (2) of this section:

(1) Annual quantity of each carbonate-based raw material charged to each continuous 

glass melting furnace and for all furnaces combined (tons).

(2) Annual quantity of glass produced by each glass melting furnace and by all furnaces 

combined (tons).

(b) If a CEMS is not used to determine CO2 emissions from continuous glass melting 

furnaces, and process CO2 emissions are calculated according to the procedures specified in § 
74

98.143(b), then you must report the following information as specified in paragraphs (b)(1) 

through (b)(9) of this section:

(1) Annual process emissions of CO2 (metric tons) for each continuous glass melting 

furnace and for all furnaces combined.

(2) Annual quantity of each carbonate-based raw material charged (tons) to each 

continuous glass melting furnace and for all furnaces combined.

(3) Annual quantity of glass produced (tons) from each continuous glass melting furnace 

and from all furnaces combined.

(4) [Reserved]Carbonate-based mineral mass fraction (percentage, expressed as a 

decimal) for each carbonate-based raw material charged to a continuous glass melting furnace.

(5) Results of all tests used to verify the carbonate-based mineral mass fraction for each 

carbonate-based raw material charged to a continuous glass melting furnace, as specified in 

paragraphs (b)(5)(i) through (b)(5)(iii) of this section.

(i) Date of test.

(ii) Method(s) and any variations used in the analyses.

(iii) Mass fraction of each sample analyzed.

(6) [Reserved]The fraction of calcination achieved for each carbonate-based raw 

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

(7) Method used to determine fraction of calcination.

(8) Total number of continuous glass melting furnaces.

(9) The number of times in the reporting year that missing data procedures were followed 

to measure monthly quantities of carbonate-based raw materials or mass fraction of the 

carbonate-based minerals for any continuous glass melting furnace (months).
75

Subpart O—HCFC–22 Production and HFC–23 Destruction

(a) In addition to the information required by § 98.3(c), the HCFC–22 production facility 

shall report the following information at the facility level:

§ 98.156 Data reporting requirements.

(1) Annual mass of HCFC–22 produced in metric tons.

(2) [Reserved]Loss Factor used to account for the loss of HCFC– 22 upstream of the 

measurement.

(3) Annual mass of reactants fed into the process in metric tons of reactant.

(4) The mass (in metric tons) of materials other than HCFC–22 and HFC–23 (i.e.

(5) The method for tracking startups, shutdowns, and malfunctions and HFC–23 

generation/emissions during these events.

, 

unreacted reactants, HCl and other by-products) that occur in more than trace concentrations and 

that are permanently removed from the process.

(6) The names and addresses of facilities to which any HFC–23 was sent for destruction, 

and the quantities of HFC–23 (metric tons) sent to each.

(7) [Reserved]Annual mass of the HFC–23 generated in metric tons.

(8) [Reserved]Annual mass of any HFC–23 sent off site for sale in metric tons.

(9) [Reserved]Annual mass of any HFC–23 sent off site for destruction in metric tons.

(10) [Reserved]Mass of HFC–23 in storage at the beginning and end of the year, in 

metric tons.

(11) Annual mass of HFC–23 emitted in metric tons.

(12) Annual mass of HFC–23 emitted from equipment leaks in metric tons.

(13) Annual mass of HFC–23 emitted from process vents in metric tons.
76

(b) In addition to the information required by § 98.3(c), facilities that destroy HFC–23 

shall report the following for each HFC–23 destruction process:

(1) [Reserved]Annual mass of HFC–23 fed into the destruction device.

(2) [Reserved]Annual mass of HFC–23 destroyed.

(3) Annual mass of HFC–23 emitted from the destruction device.

(c) Each HFC–23 destruction facility shall report the concentration (mass fraction) of 

HFC–23 measured at the outlet of the destruction device during the facility's annual HFC–23 

concentration measurements at the outlet of the device.

(d) If the HFC–23 concentration measured pursuant to § 98.154(l) is greater than that 

measured during the performance test that is the basis for the destruction efficiency (DE), the 

facility shall report the revised destruction efficiency calculated under § 98.154(l) and the values 

used to calculate it, specifying whether § 98.154(l)(1) or § 98.154(l)(2) has been used for the 

calculation. Specifically, the facility shall report the following:

(1) [Reserved]Flow rate of HFC–23 being fed into the destruction device in kg/hr.

(2) Concentration (mass fraction) of HFC–23 at the outlet of the destruction device.

(3) Flow rate at the outlet of the destruction device in kg/hr.

(4) Emission rate (in kg/hr) calculated from paragraphs (d)(2) and (d)(3) of this section.

(5) [Reserved]Destruction efficiency (DE) calculated from paragraphs (d)(1) and (d)(4) 

of this section.

(e) By March 31, 2011 or within 60 days of commencing HFC–23 destruction, HFC–23 

destruction facilities shall submit a one-time report including the following information for each 

destruction process:

(1) [Reserved]Destruction efficiency (DE).
77

(2) The methods used to determine destruction efficiency.

(3) The methods used to record the mass of HFC–23 destroyed.

(4) The name of other relevant federal or state regulations that may apply to the 

destruction process.

(5) If any changes are made that affect HFC–23 destruction efficiency or the methods 

used to record volume destroyed, then these changes must be reflected in a revision to this report. 

The revised report must be submitted to EPA within 60 days of the change.

Subpart P—Hydrogen Production

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) or (b) of this section, as appropriate, and paragraphs (c) 

throughand (de) of this section:

§ 98.166 Data reporting requirements.

(a) If a CEMS is used to measure CO2 emissions, then you must report the relevant 

information required under § 98.36 for the Tier 4 Calculation Methodology and the following 

information in this paragraph (a):

(1) Unit identification number and annual CO2 emissions.

(2) Annual quantity of hydrogen produced (metric tons) for each process unit and for all 

units combined.

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

unit and for all units combined.

(b) If a CEMS is not used to measure CO2 emissions, then you must report the following 

information for each hydrogen production process unit:

(1) Unit identification number and annual CO2 emissions.
78

(2) [Reserved]Monthly consumption of each fuel and feedstock used for hydrogen 

production and its type (scf of gaseous fuels and feedstocks, gallons of liquid fuels and 

feedstocks, kg of solid fuels and feedstocks).

(3) Annual quantity of hydrogen produced (metric tons).

(4) Annual quantity of ammonia produced, if applicable (metric tons).

(5) [Reserved]Monthly analyses of carbon content for each fuel and feedstock used in 

hydrogen production (kg carbon/kg of gaseous and solid fuels and feedstocks, (kg carbon per 

gallon of liquid fuels and feedstocks).

(6) [Reserved]Monthly analyses of the molecular weight of gaseous fuels and feedstocks 

(kg/kg-mole) used, if any.

(7) Name and annual quantity (metric tons) of each carbon-containing fuel and feedstock.

(c) Quantity of CO2 collected and transferred off site in either gas, liquid, or solid forms, 

following the requirements of subpart PP of this part.

(d) Annual quantity of carbon other than CO2 collected and transferred off site in either 

gas, liquid, or solid forms (kg carbon).

(e) Annual methanol production (metric tons), if this quantity is not reported under 

subpart X of this part.

Subpart Q—Iron and Steel Production

In addition to the information required by § 98.3(c), each annual report must contain the 

information required in paragraphs (a) through (h) of this section for each coke pushing 

operation; taconite indurating furnace; basic oxygen furnace; non-recovery coke oven battery; 

sinter process; EAF; decarburization vessel; direct reduction furnace; and flare burning coke 

oven gas or blast furnace gas. For reporting year 2010, the information required in paragraphs (a) 

§ 98.176 Data reporting requirements.
79

through (h) of this section is not required for decarburization vessels that are not argon-oxygen 

decarburization vessels. For reporting year 2011 and each subsequent reporting year, the 

information in paragraphs (a) through (h) of this section must be reported for all decarburization 

vessels.

(a) Unit identification number and annual CO2 emissions (in metric tons).

(b) If a CEMS is used to measure CO2 emissions, then you must report Tthe annual 

production quantity for the production unit (in metric tons) for taconite pellets, coke, sinter, iron, 

and raw steel.

(c) If a CEMS is used to measure CO2 emissions, then you must report the relevant 

information required under § 98.36 for the Tier 4 Calculation Methodology.

(d) If a CEMS is not used to measure CO2 emissions, then you must report for each 

process whether the emissions were determined using the carbon mass balance method in § 

98.173(b)(1) or the site-specific emission factor method in § 98.173(b)(2).

(e) If you use the carbon mass balance method in § 98.173(b)(1) to determine CO2

emissions, you must report the following information for each process:

(1) [Reserved]The carbon content of each process input and output used to determine 

CO2 emissions.

(2) Whether the carbon content was determined from information from the supplier or by 

laboratory analysis, and if by laboratory analysis, the method used.

(3) [Reserved]The annual volume of each type of gaseous fuel (reported separately for 

each type in standard cubic feet), the annual volume of each type of liquid fuel (reported 

separately for each type in gallons), and the annual mass (in metric tons) of each other process 

inputs and outputs used to determine CO2 emissions.
80

(4) [Reserved]The molecular weight of gaseous fuels.

(5) If you used the missing data procedures in § 98.175(b), you must report how the 

monthly mass for each process input or output with missing data was determined and the number 

of months the missing data procedures were used.

(6) The information specified in paragraphs (e)(6)(i) through (vi) of this section 

aggregated for all process units for which CO2 emissions were determined using the mass 

balance method in § 98.173(b)(1), except as provided in § 98.174(b)(4). 

(i) The annual mass (metric tons) of all gaseous, liquid, and solid fuels (combined) used 

in process units for which CO2 emissions were determined using Equations Q-1 through Q-7 of 

this section, calculated as specified in Equation Q-9 of this section.

Fuel = �∑ Fg,i ∗ MWi

MVC

n

i=1 ∗ 0.001 + Fl,i ∗ ρl,i ∗ 0.001 + Fs,i� (Eq. Q-9)

Where:

Fuel = Annual mass of all gaseous, liquid, and solid fuels used in process 

units (metric tons).

n = Number of process units where fuel is used.

Fg,i = Annual volume of gaseous fuel combusted (“(Fg)” in Equations Q-1, 

Q-4 and Q-7 of this section) for each process (scf).

MWi = Molecular weight of gaseous fuel used in each process (kg/kg-mole).

MVC = Molar volume conversion factor at standard conditions, as defined in 

§ 98.6. Use 849.5 scf per kg mole if you select 68 °F as standard 

temperature and 836.6 scf per kg mole if you select 60 °F as standard 

temperature.

Fl,i = Annual volume of the liquid fuel combusted (“(Fl)” included in 

Equation Q-1 of this section) for each process unit (gallons).

Fs,i = Annual mass of the solid fuel combusted (“(Fs)” in Equation Q-1 of 

this section) for each process unit (metric tons). 

ρl,i = Density of the liquid fuel (kg/gallon).

0.001 = Conversion factor from kg to metric tons.
81

(ii) The annual mass (metric tons) of all non-fuel material inputs (combined) specified in 

Equations Q-1 through Q-7 of this section, calculated as specified in Equation Q-10 of this 

section.

NFI = (∑ O + Iron + Scrap + Flux + Carbon + Coal + Feed + Electrode + Steelin n

i=1 +

Ore + Other) (Eq. Q-10)

Where:

NFI = Annual mass of all non-fuel inputs (to all process unit types) specified 

in Equations Q-1 through Q-7 of this section (metric tons).

n = Number of process units, all process types.

O = Annual mass of greenball (taconite) pellets fed to the taconite 

furnace(s) (metric tons).

Iron = Annual mass of molten iron charged to the basic oxygen furnace(s) 

plus annual mass of direct reduced iron charged to the EAF(s) (metric 

tons).

Scrap = Annual mass of ferrous scrap charged to the basic oxygen furnace(s) 

and EAF(s) (metric tons).

Flux = Annual mass of flux materials charged to the basic oxygen furnace(s) 

and EAF(s) (metric tons).

Carbon = Annual mass of carbonaceous materials (e.g., coal, coke) charged to 

the basic oxygen furnace(s), EAF(s), and direct reduction furnace(s) 

(metric tons).

Coal = Annual mass of coal charged to the coke oven battery(s) (metric tons).

Feed = Annual mass of sinter feed material charged to the sinter process(es) 

(metric tons).

Electrode = Annual mass of carbon electrode consumed in the EAF(s) (metric 

tons).

Steelin = Annual mass of molten steel charged to the decarburization vessels 

(metric tons).

Ore = Annual mass of iron ore or iron ore pellets fed to the direct reduction 

furnace(s) (metric tons).

Other = Annual mass of other materials charged to the direction reduction 

furnace(s) (metric tons).
82

(iii) The annual mass (metric tons) of all solid and liquid products and byproducts 

(combined) specified in Equations Q-1 through Q-7 of this section, calculated as specified in 

Equation Q-11 of this section.

Products = (∑n

i=1 P + R + Steelout + Slag + Coke + Sinter + Iron + NM ) (Eq. Q-11)

Where:

Products = Annual mass of all solid and liquid products and by-products (from all 

process units) specified in Equations Q-1 through Q-7 of this section

(metric tons).

n = Number of process units, all types.

P = Annual mass of fired pellets produced by the taconite furnace (metric 

tons).

R = Annual mass of air pollution control residue from all process units 

(metric tons).

Steelout = Annual mass of steel produced by the basic oxygen furnace(s), 

EAF(s) and decarburization vessel(s) (metric tons).

Slag = Annual mass of slag produced by the basic oxygen furnace(s) and 

EAF(s) (metric tons).

Coke = Annual mass of coke produced by the non-recovery coke batteries 

(metric tons).

Sinter = Annual mass of sinter produced from the sinter process(es) (metric 

tons).

Iron = Annual mass of iron produced from the direct reduction furnace 

(metric tons).

NM = Annual mass of non-metallic materials produced by the direct 

reduction furnace (metric tons).

(iv) The weighted average carbon content of all gaseous, liquid, and solid fuels 

(combined) included in Equation Q-9 of this section, calculated as specified in Equation Q-12 of 

this section.

CFavg = � ∑ Fg,i ∗

MWi

MVC

n

i=1 ∗Cgf,i∗0.001+Fl,i∗Clf,i∗0.001+ Fs,i∗Csf �

Fuel (Eq. Q-12)

Where:
83

CFavg = Weighted average carbon content of all gaseous, liquid, and solid 

fuels included in Equation Q-9 of this section (weight fraction).

n = Number of gaseous, liquid, and solid fuel input to each process unit as 

used in Equation Q-9.

Cgf,i = Average carbon content of the gaseous fuel used in each process, 

from the fuel analysis results (kg C per kg of fuel).

Clf,i = Carbon content of the liquid fuel used in each process, from the fuel 

analysis results (kg C per gallon of fuel.

Csf = Carbon content of the solid fuel used in each process, from the fuel 

analysis (expressed as a decimal fraction, e.g., 95% = 0.95).

Fuel = Annual mass of all gaseous, liquid, and solid fuels used in process 

units (metric tons), as calculated in Equation Q-9.

(v) The weighted average carbon content of all non-fuel inputs to all process units 

(combined) included in Equation Q-10 of this section, calculated as specified in Equation Q-13 

of this section.

CIavg = �∑ NFIi∗CNFIi n

i=1 �

NFI (Eq. Q-13)

Where:

CIavg = Weighted average carbon content of all non-fuel inputs to all process 

units included in Equation Q-10 of this section (weight fraction).

n = Number of non-fuel inputs to all process units as used in Equation Q10.

NFIi = Annual mass of each non-fuel input used in Equation Q-10 (metric 

tons).

CNFIi = Average carbon content of each non-fuel input used in Equation Q-10 

(expressed as a decimal fraction).

NFI = Total of all non-fuel inputs to all process units (metric tons).

(vi) The weighted average carbon content of all solid and liquid products and byproducts 

from all process units (combined) included in Equation Q-11 of this section, calculated as 

specified in Equation Q-14 of this section.

CPavg = �∑ Producti∗CPi n

i=1 �

Products (Eq. Q-14)
84

Where:

CPavg = Weighted average carbon content of all solid and liquid products and 

byproducts from all process units (weight fraction).

n = Number of products and byproducts from each process unit as used in 

Equation Q-11 of this section.

Producti = Annual mass of each product or byproduct used in Equation Q-11 of 

this section (metric tons).

Cp,i = Average carbon content of each product or byproduct used in 

Equation Q-11 of this section (expressed as a decimal fraction).

Products = Mass of all products and byproducts from all process units, calculated 

in Equation Q-11 of this section (metric tons).

(f) If you used the site-specific emission factor method in § 98.173(b)(2) to determine 

CO2 emissions, you must report the following information for each process:

(1) The measured average hourly CO2 emission rate during the test (in metric tons per 

hour).

(2) [Reserved]The average hourly feed or production rate (as applicable) during the test 

(in metric tons per hour).

(3) [Reserved]The site-specific emission factor (in metric tons of CO2 per metric ton of 

feed or production, as applicable).

(4) [Reserved]The annual feed or production rate (as applicable) used to estimate annual 

CO2 emissions (in metric tons).

(g) [Reserved]The annual amount of coal charged to the coke ovens (in metric tons).

(h) For flares burning coke oven gas or blast furnace gas, the information specified in § 

98.256(e) of subpart Y (Petroleum Refineries) of this part.

Subpart R—Lead Production

§ 98.186 Data reporting procedures.
85

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) or (b) of this section, as applicable.

(a) If a CEMS is used to measure CO2 emissions according to the requirements in § 

98.183(a) or (b)(1), then you must report under this subpart the relevant information required by 

§ 98.36 and the information specified in paragraphs (a)(1) through (a)(4) of this section.

(1) Identification number of each smelting furnace.

(2) Annual lead product production capacity (tons).

(3) Annual production for each lead product (tons).

(4) Total number of smelting furnaces at facility used for lead production.

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

according to the requirements in § 98.183(b)(2)(i) and (b)(2)(ii), then you must report the 

information specified in paragraphs (b)(1) through (b)(9) of this section.

(1) Identification number of each smelting furnace. (2) Annual process CO2 emissions (in 

metric tons) from each smelting furnace as determined by Equation R–1 of this subpart.

(3) Annual lead product production capacity for the facility and each smelting 

furnace(tons).

(4) Annual production for each lead product (tons).

(5) Total number of smelting furnaces at facility used for production of lead products 

reported in paragraph (b)(4) of this section.

(6) [Reserved]Annual material quantity for each material used for the calculation of 

annual process CO2 emissions using Equation R–1 of this subpart for each smelting furnace 

(tons).
86

(7) [Reserved]Annual average of the carbon content determinations for each material 

used for the calculation of annual process CO2 emissions using Equation R–1 of this subpart for 

each smelting furnace.

(8) List the method used for the determination of carbon content for each material used 

for the calculation of annual process CO2 emissions using Equation R–1 of this subpart for each

smelting furnace reported in paragraph (b)(7) of this section (e.g.

(9) If you use the missing data procedures in § 98.185(b), you must report how the 

monthly mass of carbon-containing materials with missing data was determined and the number 

of months the missing data procedures were used.

, supplier provided information, 

analyses of representative samples you collected).

Subpart S—Lime Manufacturing

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) or (b) of this section, as applicable.

§ 98.196 Data reporting requirements.

(a) If a CEMS is used to measure CO2 emissions, then you must report under this subpart 

the relevant information required by § 98.36 and the information listed in paragraphs (a)(1) 

through (8) of this section.

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

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

(3) Beginning and end of year inventories for each lime product that is produced, by type.

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

type.

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

(6) Annual amount of lime product sold, by type (tons).
87

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

(8) Annual amount of lime product not sold, by type (tons).

(b) If a CEMS is not used to measure CO2 emissions, then you must report the 

information listed in paragraphs (b)(1) through (1718) of this section.

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

(2) [Reserved]Monthly emission factors for each lime type produced.

(3) [Reserved]Monthly emission factors for each calcined byproduct/waste by lime type 

that is sold.

(4) Standard method used (ASTM or NLA testing method) to determine chemical 

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

(5) [Reserved]Monthly results of chemical composition analysis of each type of lime 

product produced and calcined byproduct/waste sold.

(6) [Reserved]Annual results of chemical composition analysis of each type of lime 

byproduct/waste that is not sold.

(7) Method used to determine the quantity of lime produced and/or lime sold.

(8) [Reserved]Monthly amount of lime product sold, by type (tons).

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

(10) [Reserved]Monthly amount of calcined lime byproduct/waste sold, by type (tons).

(11) [Reserved]Annual amount of calcined lime byproduct/waste that is not sold, by type 

(tons).

(12) [Reserved]Monthly weight or mass of each lime type produced (tons).

(13) Beginning and end of year inventories for each lime product that is produced.

(14) Beginning and end of year inventories for calcined lime byproducts/wastes sold.
88

(15) Annual lime production capacity (tons) per facility.

(16) Number of times in the reporting year that missing data procedures were followed to 

measure lime production (months) or the chemical composition of lime products sold (months).

(17) Indicate whether CO2 was used on-site (i.e.

(i) The annual amount of CO2 captured for use in the on-site process.

, for use in a purification process). If CO2

was used on-site, provide the information in paragraphs (b)(17)(i) and (ii) of this section.

(ii) The method used to determine the amount of CO2 captured.

(18) Annual quantity (metric tons) of lime product sold, by type.

Subpart U—Miscellaneous Uses of Carbonate

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) through (g) of this section at the facility level, as 

applicable.

§ 98.216 Data reporting requirements.

(a) Annual CO2 emissions from miscellaneous carbonate use (metric tons).

(b) [Reserved]Annual mass of each carbonate type consumed (tons).

(c) Measurement method used to determine the mass of carbonate.

(d) Method used to calculate emissions.

(e) If you followed the calculation method of § 98.213(b)(1)(i), you must report the 

information in paragraphs (e)(1) through (e)(3) of this section.

(1) [Reserved]Annual carbonate consumption by carbonate type (tons).

(2) [Reserved]Annual calcination fractions used in calculations.

(3) If you determined the calcination fraction, indicate which standard method was used.

(f) [Reserved]If you followed the calculation method of § 98.213(b)(1)(ii), you must 

report the information in paragraphs (f)(1) and (f)(2) of this section.
89

(1) Annual carbonate input by carbonate type (tons).

(2) Annual carbonate output by carbonate type (tons).

(g) Number of times in the reporting year that missing data procedures were followed to 

measure carbonate consumption, carbonate input or carbonate output (months).

Subpart V—Nitric Acid Production

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) through (pq) of this section.

§ 98.226 Data reporting requirements.

(a) Train identification number.

(b) Annual process N2O emissions from each nitric acid train (metric tons).

(c) [Reserved]

(d) [Reserved]Annual nitric acid production from each nitric acid train during which N2O 

abatement technology is operating (ton acid produced, 100 percent acid basis).

(e) Annual nitric acid production from the nitric acid facility (tons, 100 percent acid 

basis).

(f) Number of nitric acid trains.

(g) Number of different N2O abatement technologies per nitric acid train “t”.

(h) Abatement technologies used (if applicable).

(i) Abatement technology destruction efficiency for each abatement technology (percent 

destruction).

(j) Abatement utilization factor for each abatement technology (fraction of annual 

production that abatement technology is operating).

(k) Type of nitric acid process used for each nitric acid train (low, medium, high, or dual 

pressure).
90

(l) Number of times in the reporting year that missing data procedures were followed to 

measure nitric acid production (months).

(m) If you conducted a performance test and calculated a site-specific emissions factor 

according to § 98.223(a)(1), each annual report must also contain the information specified in 

paragraphs (m)(1) through (7) of this section.

(1) [Reserved]Emission factor calculated for each nitric acid train (lb N2O/ton nitric acid, 

100 percent acid basis).

(2) Test method used for performance test.

(3) [Reserved]Production rate per test run during performance test (tons nitric acid 

produced/hr, 100 percent acid basis).

(4) N2O concentration per test run during performance test (ppm N2O).

(5) Volumetric flow rate per test run during performance test (dscf/hr).

(6) Number of test runs during performance test.

(7) Number of times in the reporting year that a performance test had to be repeated 

(number).

(n) If you requested Administrator approval for an alternative method of determining 

N2O emissions under § 98.223(a)(2), each annual report must also contain the information 

specified in paragraphs (n)(1) through (4) of this section. (n)(1) through (n)(4) of this section for 

each nitric acid production facility.

(1) Name of alternative method.

(2) Description of alternative method.

(3) Request date.

(4) Approval date.
91

(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.

(q) Annual percent N2O emission reduction for all production units combined.

Subpart X—Petrochemical Production

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a), (b), or (c) of this section, as appropriate for each process 

unit.

§ 98.246 Data reporting requirements.

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

information specified in paragraphs (a)(1) through (a)(1113) of this section for each type of 

petrochemical produced, reported by process unit.

(1) The petrochemical process unit ID number or other appropriate descriptor.

(2) The type of petrochemical produced, names of other products, and names of carboncontaining feedstocks.

(3) Annual CO2 emissions calculated using Equation X–4 of this subpart.

(4) Each of the monthly volume, mass, and carbon content values used in Equations X–1 

through X–3 of this subpart (i.e.

(5) Annual quantity of each type of petrochemical produced from each process unit 

(metric tons).

, the directly measured values, substitute values, or the 

calculated values based on other measured data such as tank levels or gas composition) and the 

molecular weights for gaseous feedstocks and products used in Equation X–1 of this subpart, and 

tThe temperature (in °F) at which the gaseous feedstock and product volumes used in Equation 

X–1 of this subpart were determined. Indicate whether you used the alternative to sampling and 

analysis specified in § 98.243(c)(4).
92

(6) Name of each method listed in § 98.244 used to determine a measured parameter (or 

description of manufacturer's recommended method).

(7) [Reserved]

(8) Identification of each combustion unit that burned both process off-gas and 

supplemental fuel.

(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.

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

elect to report the annual mass of carbon released in fugitive emissions and in process vents that 

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

engineering analyses. These values are not to be used in the mass balance calculation.

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

method under § 98.244(b)(4)(xv)(B), report the information listed in paragraphs (a)(11)(i) 

through (a)(11)(iv) of this section. Include the information in paragraph (a)(11)(i) of this section 

in each annual report. Include the information in paragraphs (a)(11)(ii) and (a)(11)(iii) of this 

section only in the first applicable annual report, and provide any changes to this information in 

subsequent annual reports.

(i) Name or title of the analytical method.

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

98.244(b)(4)(i) through (xiv), you may provide a copy of only the sections that differ from the 

listed method.
93

(iii) An explanation of why an alternative to the methods listed in §§ 98.244(b)(4)(i) 

through (xii) is needed.

(12) Name and annual quantity (in metric tons) of each carbon-containing feedstock 

included in Equations X-1, X-2, and X-3 of § 98.243 of this subpart.

(13) Name and annual quantity (in metric tons) of each product included in Equations X1, X-2, and X-3 of § 98.243 of this subpart.

(b) If you measure emissions in accordance with § 98.243(b), then you must report the 

information listed in paragraphs (b)(1) through (b)(810) of this section.

(1) The petrochemical process unit ID or other appropriate descriptor, and the type of 

petrochemical produced.

(2) For CEMS used on stacks 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.

(3) For CEMS used on stacks that are not used for stationary combustion units, report the 

information required under § 98.36(e)(2)(vi).

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

(except flare stacks) that handle process vent emissions and emissions from stationary 

combustion units that burn process off-gas for the petrochemical process unit. For each 

stationary combustion unit (or group of 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.
94

(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 CO2e. 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 CO2e.

(iii) [Reserved]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) [Reserved]The HHV (either default or annual average from measured data) used in 

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

applicable).

(6) ID or other appropriate descriptor of each stationary combustion unit that burns 

process off-gas.

(7) Information listed in § 98.256(e) of subpart Y of this part for each flare that burns 

process off-gas.

(8) Annual quantity of each type of petrochemical produced from each process unit 

(metric tons).

(9) Name and annual quantity (in metric tons) of each carbon-containing feedstock.

(10) Name and annual quantity (in metric tons) of each carbon-containing co-product.
95

(c) If you comply with the combustion methodology specified in § 98.243(d), you must 

report under this subpart the information listed in paragraphs (c)(1) through (c)(5) of this section.

(1) The ethylene process unit ID or other appropriate descriptor.

(2) For each stationary combustion unit that burns ethylene process off-gas (or group of 

stationary sources with a common pipe), except flares, the relevant information listed in § 98.36 

for the applicable Tier methodology. For each stationary combustion unit or group of units (as 

applicable) that burns ethylene process off-gas, provide an estimate based on engineering 

judgment of the fraction of the total emissions that is attributable to combustion of off-gas from 

the ethylene process unit.

(3) Information listed in § 98.256(e) of subpart Y of this part for each flare that burns 

ethylene process off-gas.

(4) Name and annual quantity of each feedstock.

(5) Annual quantity of ethylene produced from each process unit (metric tons).

Subpart Y—Petroleum Refineries

In addition to the reporting requirements of § 98.3(c), you must report the information 

specified in paragraphs (a) through (q) of this section.

§ 98.256 Data reporting requirements.

(a) For combustion sources, follow the data reporting requirements under subpart C of 

this part (General Stationary Fuel Combustion Sources).

(b) For hydrogen plants, follow the data reporting requirements under subpart P of this 

part (Hydrogen Production).

(c)–(d) [Reserved]

(e) For flares, owners and operators shall report:

(1) The flare ID number (if applicable).
96

(2) A description of the type of flare (steam assisted, air-assisted).

(3) A description of the flare service (general facility flare, unit flare, emergency only or 

back-up flare).

(4) The calculated CO2, CH4, and N2O annual emissions for each flare, expressed in 

metric tons of each pollutant emitted.

(5) A description of the method used to calculate the CO2 emissions for each flare (e.g.

(6) If you use Equation Y–1a of this subpart, an indication of whether daily or weekly 

measurement periods are used, the annual volume of flare gas combusted (in scf/year) and the 

annual average molecular weight (in kg/kg-mole), the molar volume conversion factor (in scf/kgmole), and annual average carbon content of the flare gas (in kg carbon per kg flare gas).

, 

reference section and equation number).

(7) If you use Equation Y–1b of this subpart, an indication of whether daily or weekly 

measurement periods are used, the annual volume of flare gas combusted (in scf/year), the molar 

volume conversion factor (in scf/kg-mole), the annual average CO2 concentration (volume or 

mole percent), the number of carbon containing compounds other than CO2 in the flare gas 

stream, and for each of the carbon containing compounds other than CO2 in the flare gas stream:

(i) The annual average concentration of the compound (volume or mole percent).

(ii) [Reserved]The carbon mole number of the compound (moles carbon per mole 

compound).

(8) If you use Equation Y–2 of this subpart, an indication of whether daily or weekly 

measurement periods are used, the annual volume of flare gas combusted (in million (MM) 

scf/year), the annual average higher heating value of the flare gas (in mmBtu/mmscf), and an 

indication of whether the annual volume of flare gas combusted and the annual average higher 
97

heating value of the flare gas were determined using standard conditions of 68 °F and 14.7 psia 

or 60 °F and 14.7 psia.

(9) If you use Equation Y–3 of this subpart, the annual volume of flare gas combusted (in 

MMscf/year) during normal operations, the annual average higher heating value of the flare gas 

(in mmBtu/mmscf), the number of SSM events exceeding 500,000 scf/day, the volume of gas 

flared (in scf/event), the average molecular weight (in kg/kg-mole), the molar volume conversion 

factor (in scf/kg-mole), and carbon content of the flare gas (in kg carbon per kg flare) for each 

SSM event over 500,000 scf/day.

(10) The basis for the value of the fraction of carbon in the flare gas contributed by 

methane used in Equation Y–4 of this subpart and the basis for its value.

(11) If using Equation Y-3 of this subpart, report:

(i) Annual quantity of flare gas combusted (in MMscf per year).

(ii) Annual average molecular weight of flare gas combusted (in mmBtu per MMscf).

(iii) Annual average carbon content of flare gas combusted (expressed as a decimal 

fraction).

(f) For catalytic cracking units, traditional fluid coking units, and catalytic reforming 

units, owners and operators shall report:

(1) The unit ID number (if applicable).

(2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic 

cracking unit, traditional fluid coking unit, or catalytic reforming unit).

(3) Maximum rated throughput of the unit, in bbl/stream day.

(4) The calculated CO2, CH4, and N2O annual emissions for each unit, expressed in 

metric tons of each pollutant emitted.
98

(5) A description of the method used to calculate the CO2 emissions for each unit (e.g.

(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 subpart (

, 

reference section and equation number).

e.g.

(7) If you use Equation Y–6 of this subpart, the annual average exhaust gas flow rate, 

%CO2, and %CO, and the molar volume conversion factor (in scf/kg-mole).

, 

subpart C of this part in the case of a CO boiler).

(8) If you use Equation Y–7a of this subpart, the annual average flow rate of inlet air and 

oxygen-enriched air, %O2, %Ooxy, %CO2, and %CO.

(9) If you use Equation Y–7b of this subpart, the annual average flow rate of inlet air and 

oxygen-enriched air, %N2,oxy, and %N2,exhaust.

(10) If you use Equation Y–8 of this subpart, the basis for the value of the coke burn-off 

factor, annual throughput of unit, and the average carbon content of coke and the basis for the 

value.

(11) Indicate whether you use a measured value, a unit-specific emission factor, or a 

default emission factor for CH4 emissions. If you use a unit-specific emission factor for CH4, 

report the unit-specific emission factor for CH4, the units of measure for the unit-specific factor, 

the activity data for calculating emissions (e.g., if the emission factor is based on coke burn-off 

rate, the annual quantity of coke burned), and the basis for the factor.
99

(12) Indicate whether you use a measured value, a unit-specific emission factor, or a 

default emission factor for N2O emissions. If you use a unit-specific emission factor for N2O, 

report the unit-specific emission factor for N2O, the units of measure for the unit-specific factor, 

the activity data for calculating emissions (e.g.

(13) If you use Equation Y–11 of this subpart, the number of regeneration cycles or 

measurement periods during the reporting year, and the average coke burn-off quantity per cycle 

or measurement period, and the average carbon content of the coke.

, if the emission factor is based on coke burn-off 

rate, the annual quantity of coke burned), and the basis for the factor.

(g) For fluid coking unit of the flexicoking type, the owner or operator shall report:

(1) The unit ID number (if applicable).

(2) A description of the type of unit.

(3) Maximum rated throughput of the unit, in bbl/stream day.

(4) Indicate whether the GHG emissions from the low heat value gas are accounted for in 

subpart C of this part or § 98.253(c).

(5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, 

also report the calculated annual CO2, CH4, and N2O emissions for each unit, expressed in metric 

tons of each pollutant emitted, and the applicable equation input parameters specified in 

paragraphs (f)(7) through (f)(13) of this section.

(h) For sulfur recovery plants and for emissions from sour gas sent off-site for sulfur 

recovery, the owner and operator shall report:

(1) The plant ID number (if applicable).

(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 
100

of the method used to calculate CO2 annual emissions for the sulfur recovery plant (e.g.

(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.

, CO2

CEMS, Equation Y–12, or process vent method in § 98.253(j)).

(4) [Reserved]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).

(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 of 

this subpart. If so, then report:

(i) Tthe value of the correction,. 

(ii) If the following data are not used to calculate the recycling correction factor, report 

the information specified in paragraphs (h)(5)(ii)(A) through (C) of this section.

(A) The annual volume of recycled tail gas (in scf/year) and theonly.

(B) The annual average mole fraction of carbon in the tail gas (in kg-mole C/kg-mole 

gas).

(C) Indicate whether you used the default (95%) or a unit specific correction, and if used, 

report the approach used.

(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 and the annual 

process CO2 emissions calculated according to § 98.253(f)(1). Report the CO2 annual emissions 
101

associated with fuel combustion subpart C of this part (General Stationary Fuel Combustion 

Sources).

(7) If you use the process vent method in § 98.253(j) for a non-Claus sulfur recovery 

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

(i) For coke calcining units, the owner and operator shall report:

(1) The unit ID number (if applicable).

(2) Maximum rated throughput of the unit, in metric tons coke calcined/stream day.

(3) The calculated CO2, CH4, and N2O annual emissions for each unit, expressed in 

metric tons of each pollutant emitted.

(4) A description of the method used to calculate the CO2 emissions for each unit (e.g.

(5) If you use Equation Y–13 of this subpart, annual mass and carbon content of green 

coke fed to the unit, the annual mass and carbon content of marketable coke produced, the annual 

mass of coke dust removed from the process through dust collection systems, and an indication 

of whether coke dust is recycled to the unit (

, 

reference section and equation number).

e.g.

(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 and the annual 

process CO2 emissions calculated according to § 98.253(g)(1).

, all dust is recycled, a portion of the dust is 

recycled, or none of the dust is recycled).

(7) Indicate whether you use a measured value, a unit-specific emission factor or a 

default for CH4 emissions. If you use a unit-specific emission factor for CH4, the unit-specific 

emission factor for CH4, the units of measure for the unit-specific factor, the activity data for 
102

calculating emissions (e.g.

(8) Indicate whether you use a measured value, a unit-specific emission factor, or a 

default emission factor for N2O emissions. If you use a unit-specific emission factor for N2O, 

report the unit-specific emission factor for N2O, the units of measure for the unit-specific factor, 

the activity data for calculating emissions (

, if the emission factor is based on coke burn-off rate, the annual 

quantity of coke burned), andreport the basis for the factor.

e.g.

(j) For asphalt blowing operations, the owner or operator shall report:

, if the emission factor is based on coke burn-off 

rate, the annual quantity of coke burned), and the basis for the factor.

(1) The unit ID number (if applicable).

(2) [Reserved]The quantity of asphalt blown (in million bbl) at the unit in the reporting 

year.

(3) The type of control device used to reduce methane (and other organic) emissions from 

the unit.

(4) The calculated annual CO2 and CH4 emissions for each unit, expressed in metric tons 

of each pollutant emitted.

(5) If you use Equation Y–14 of this subpart, the basis for the CO2 emission factor used

and the basis for the value.

(6) If you use Equation Y–15 of this subpart, the basis for the CH4 emission factor used

and the basis for the value.

(7) If you use Equation Y–16 of this subpart, the basis for the carbon emission factor 

used and the basis for the value.
103

(8) If you use Equation Y–16b of this subpart, the CO2 emission factor used and the basis 

for its valuethe CO2 emission factor used and the basis for the carbon emission factor used and 

the basis for its value.

(9) If you use Equation Y–17 of this subpart, the basis for the CH4 emission factor used

and the basis for the value.

(k) For delayed coking units, the owner or operator shall report:

(1) The cumulative annual CH4 emissions (in metric tons of CH4) for all delayed coking 

units at the facility.

(2) A description of the method used to calculate the CH4 emissions for each unit (e.g.

(3) The total number of delayed coking units at the facility,; the total number of delayed 

coking drums at the facility,; and, for each coke drum or vessel: The dimensions, the typical 

gauge pressure of the coking drum when first vented to the atmosphere, typical void fraction, the 

typical drum outage (

, 

reference section and equation number).

i.e.

(4) For each set of coking drums that are the same dimensions: The, 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).

the unfilled distance from the top of the drum, in feet), the molar 

volume conversion factor (in scf/kg-mole), and annual number of coke-cutting cycles.

(5) The basis for the volumetric void fraction of the coke vessel prior to steaming and the 

basis for the mole fraction of methane in the coking gas.

(l) For each process vent subject to § 98.253(j), the owner or operator shall report:
104

(1) The vent ID number (if applicable).

(2) The unit or operation associated with the emissions.

(3) The type of control device used to reduce methane (and other organic) emissions from 

the unit, if applicable.

(4) The calculated annual CO2, CH4, and N2O emissions for each vent, expressed in 

metric tons of each pollutant emitted.

(5) The annual volumetric flow discharged to the atmosphere (in scf), and an indication 

of the measurement or estimation method, annual average mole fraction of each GHG above the 

concentration threshold or otherwise required to be reported and an indication of the 

measurement or estimation method, the molar volume conversion factor (in scf/kg-mole), and for 

intermittent vents, the number of venting events and the cumulative venting time.

(m) For uncontrolled blowdown systems, the owner or operator shall report:

(1) An indication of whether the uncontrolled blowdown emission are reported under § 

98.253(k) or § 98.253(j) or a statement that the facility does not have any uncontrolled 

blowdown systems.

(2) The cumulative annual CH4 emissions (in metric tons of CH4) for uncontrolled 

blowdown systems.

(3) For uncontrolled blowdown systems reporting under § 98.253(k), the total quantity (in 

million bbl) of crude oil plus the quantity of intermediate products received from off site that are 

processed at the facility in the reporting year,basis for the value of the methane emission factor 

used for uncontrolled blowdown systems, the basis for the value, and the molar volume 

conversion factor (in scf/kg-mole).
105

(4) For uncontrolled blowdown systems reporting under § 98.253(j), the relevant 

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

(n) For equipment leaks, the owner or operator shall report:

(1) The cumulative CH4 emissions (in metric tons of each pollutant emitted) for all 

equipment leak sources.

(2) The method used to calculate the reported equipment leak emissions.

(3) The number of each type of emission source listed in Equation Y–21 of this subpart at 

the facility.

(o) For storage tanks, the owner or operator shall report:

(1) The cumulative annual CH4 emissions (in metric tons of CH4) for all storage tanks, 

except for those used to process unstabilized crude oil.

(2) For storage tanks other than those processing unstabilized crude oil:

(i) The method used to calculate the reported storage tank emissions for storage tanks 

other than those processing unstabilized crude (i.e., either AP 42, Section 7.1 (incorporated by 

reference, see

(ii) [Reserved]The total quantity (in MMbbl) of crude oil plus the quantity of 

intermediate products received from off site that are processed at the facility in the reporting 

year.

§ 98.7), or Equation Y–22 of this section).

(3) The cumulative CH4 emissions (in metric tons of CH4) for storage tanks used to 

process unstabilized crude oil or a statement that the facility did not receive any unstabilized 

crude oil during the reporting year.

(4) For storage tanks that process unstabilized crude oil:
106

(i) The method used to calculate the reported unstabilized crude oil storage tank 

emissions.

(ii) [Reserved]The quantity of unstabilized crude oil received during the calendar year (in 

MMbbl).

(iii) [Reserved]The average pressure differential (in psi).

(iv) [Reserved]The molar volume conversion factor (in scf/kg-mole).

(v) [Reserved]The average mole fraction of CH4 in vent gas from unstabilized crude oil 

storage tanks and the basis for the mole fraction.

(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.

(5) The method used to calculate the reported storage tank emissions for storage tanks 

processing unstabilized crude oil.

(6) [Reserved]The quantity of unstabilized crude oil received during the calendar year (in 

MMbbl), the average pressure differential (in psi), and the mole fraction of CH4 in vent gas from 

the unstabilized crude oil storage tank, and the basis for the mole fraction.

(7) [Reserved]The tank-specific methane composition data and the gas generation rate 

data, if you did not use Equation Y–23.

(p) For loading operations, the owner or operator shall report:

(1) The cumulative annual CH4 emissions (in metric tons of each pollutant emitted) for 

loading operations.

(2) The quantity and types of materials loaded by vessel type (barge, tanker, marine 

vessel, etc.) that have an equilibrium vapor-phase concentration of methane of 0.5 volume 
107

percent or greater, and the type of vessels (barge, tanker, marine vessel, etc.) in which theeach 

type of material is loaded.

(3) The type of control system used to reduce emissions from the loading of material with 

an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, if any 

(submerged loading, vapor balancing, etc.).

(q) Name of each method listed in § 98.254 or a description of manufacturer's 

recommended method used to determine a measured parameter.

Subpart Z—Phosphoric Acid Production

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) through (f) of this section.

§ 98.266 Data reporting requirements.

(a) Annual phosphoric acid production by origin (as listed in Table Z–1 to this subpart) of 

the phosphate rock (tons).

(b) Annual phosphoric acid permitted production capacity (tons).

(c) Annual arithmetic average percent inorganic carbon or carbon dioxide in phosphate 

rock from monthly records (percent by weight, expressed as a decimal fraction).

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

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

(e) If you use a CEMS to measure CO2 emissions, then you must report the information 

in paragraphs (e)(1) and (e)(2) of this section.

(1) The identification number of each wet-process phosphoric acid process line.

(2) The annual CO2 emissions from each wet-process phosphoric acid process line 

(metric tons) and the relevant information required under 40 CFR 98.36 (e)(2)(vi) for the Tier 4 

Calculation Methodology.
108

(f) If you do not use a CEMS to measure emissions, then you must report the information 

in paragraphs (f)(1) through (9) of this section.

(1) Identification number of each wet-process phosphoric acid process line.

(2) Annual CO2 emissions from each wet-process phosphoric acid process line (metric 

tons) as calculated by either Equation Z–1a or Equation Z–1b of this subpart.

(3) Annual phosphoric acid permitted production capacity (tons) for each wet-process 

phosphoric acid process line (metric tons).

(4) Method used to estimate any missing values of inorganic carbon content or carbon 

dioxide content of phosphate rock for each wet-process phosphoric acid process line.

(5) [Reserved]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.

(6) [Reserved]Monthly mass of phosphate rock consumed by origin, (as listed in Table 

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

(7) Number of wet-process phosphoric acid process lines.

(8) Number of times missing data procedures were used to estimate phosphate rock 

consumption (months) and inorganic carbon contents of the phosphate rock (months).

(9) Annual process CO2 emissions from phosphoric acid production facility (metric tons).

Subpart AA—Pulp and Paper Manufacturing

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

required by § 98.36, each annual report must contain the information in paragraphs (a) through 

(km) of this section as applicable:

§ 98.276 Data reporting requirements.
109

(a) Annual emissions of CO2, biogenic CO2, CH4, biogenic CH4 N2O, and biogenic N2O 

(metric tons per year).

(b) [Reserved]Annual quantities fossil fuels by type used in chemical recovery furnaces 

and chemical recovery combustion units in short tons for solid fuels, gallons for liquid fuels and 

scf for gaseous fuels.

(c) Annual mass of the spent liquor solids combusted (short tons per year), and bBasis for 

determining the annual mass of the spent liquor solids combusted (whether based on T650 om-05 

Solids Content of Black Liquor, TAPPI (incorporated by reference, see 

(d) [Reserved]The high heat value (HHV) of the spent liquor solids used in Equation 

AA–1 of this subpart (mmBtu per kilogram).

§ 98.7) or an online 

measurement system).

(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).

(f) [Reserved]The carbon content (CC) of the spent liquor solids, used in Equation AA–2 

of this subpart (percent by weight, expressed as a decimal fraction, e.g.

(g) [Reserved]Annual quantities of fossil fuels by type used in pulp mill lime kilns in 

short tons for solid fuels, gallons for liquid fuels and scf for gaseous fuels.

, 95% = 0.95).

(h) [Reserved]Make-up quantity of CaCO3 used for the reporting year (metric tons per 

year) used in Equation AA–3 of this subpart.

(i) [Reserved]Make-up quantity of Na2CO3 used for the reporting year (metric tons per 

year) used in Equation AA–3 of this subpart.

(j) Annual steam purchases (pounds of steam per year).

(k) Annual production of pulp and/or paper products produced (metric tons).
110

(l) For each pulp mill lime kiln, report the information specified in paragraphs (l)(1) and 

(2) of this section.

(1) The quantity of calcium oxide (CaO) produced (metric tons).

(2) The percent of annual heat input, individually for each fossil fuel type.

(m) For each chemical recovery furnace and each chemical recovery combustion unit for 

which you are not using Equation C-2c of this part to calculate CO2 emissions, report the 

information specified in paragraphs (m)(1) and (2) of this section.

(1) The annual mass of steam generated (lb steam), individually for each fossil fuel type 

and for spent liquor solids.

(2) The ratio of the unit’s maximum rated heat input capacity to its design rated steam 

output capacity (mmBtu/lb steam), individually for each fossil fuel type and for spent liquor 

solids.

Subpart BB—Silicon Carbide Production

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) or (b) of this section, as applicable for each silicon 

carbide production facility.

§ 98.286 Data reporting requirements.

(a) If a CEMS is used to measure process CO2 emissions, you must report under this 

subpart the relevant information required for the Tier 4 Calculation Methodology in § 98.36 and 

the information listed in this paragraph (a):

(1) Annual consumption of petroleum coke (tons).

(2) Annual production of silicon carbide (tons).

(3) Annual production capacity of silicon carbide (tons).
111

(b) If a CEMS is not used to measure process CO2 emissions, you must report the 

information listed in this paragraph (b) for all furnaces combined:

(1) [Reserved]Monthly consumption of petroleum coke (tons).

(2) Annual production of silicon carbide (tons).

(3) Annual production capacity of silicon carbide (tons).

(4) [Reserved]Carbon content factor of petroleum coke from the supplier or as measured 

by the applicable method in § 98.284(c) for each month (percent by weight expressed as a 

decimal fraction).

(5) Whether carbon content of the petroleum coke is based on reports from the supplier or 

through self measurement using applicable ASTM standard method.

(6) [Reserved]CO2 emissions factor calculated for each month (metric tons CO2/metric 

ton of petroleum coke consumed).

(7) Sampling analysis results for carbon content of consumed petroleum coke as 

determined for QA/QC of supplier data under § 98.284(d) (percent by weight expressed as a 

decimal fraction).

(8) Number of times in the reporting year that missing data procedures were followed to 

measure the carbon contents of petroleum coke (number of months) and petroleum coke 

consumption (number of months).

Subpart CC—Soda Ash Manufacturing

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) or (b) of this section, as appropriate for each soda ash 

manufacturing facility.

§ 98.296 Data reporting requirements.
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(a) If a CEMS is used to measure CO2 emissions, then you must report under this subpart 

the relevant information required under § 98.36 and the following information in this paragraph 

(a):

(1) Annual consumption of trona or liquid alkaline feedstock for each manufacturing line 

(tons).

(2) Annual production of soda ash for each manufacturing line (tons).

(3) Annual production capacity of soda ash for each manufacturing line (tons).

(4) Identification number of each manufacturing line.

(b) If a CEMS is not used to measure CO2 emissions, then you must report the 

information listed in this paragraph (b):

(1) Identification number of each manufacturing line.

(2) Annual process CO2 emissions from each soda ash manufacturing line (metric tons).

(3) Annual production of soda ash for each manufacturing line (tons).

(4) Annual production capacity of soda ash for each manufacturing line (tons).

(5) [Reserved]Monthly consumption of trona or liquid alkaline feedstock for each 

manufacturing line (tons).

(6) [Reserved]Monthly production of soda ash for each manufacturing line (tons).

(7) [Reserved]Inorganic carbon content factor of trona or soda ash (depending on use of 

Equations CC–1 or CC–2 of this subpart) as measured by the applicable method in § 98.294(b) 

or (c) for each month (percent by weight expressed as a decimal fraction).

(8) Whether CO2 emissions for each manufacturing line were calculated using a trona 

input method as described in Equation CC–1 of this subpart, a soda ash output method as 
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described in Equation CC–2 of this subpart, or a site-specific emission factor method as 

described in Equations CC–3 through CC–5 of this subpart.

(9) Number of manufacturing lines located used to produce soda ash.

(10) If you produce soda ash using the liquid alkaline feedstock process and use the sitespecific emission factor method (§ 98.293(b)(3)) to estimate emissions then you must report the 

following relevant information for each manufacturing line or stack:

(i) Stack gas volumetric flow rate during performance test (dscfm).

(ii) Hourly CO2 concentration during performance test (percent CO2).

(iii) CO2 emission factor (metric tons CO2/metric tons of process vent flow from mine 

water stripper/evaporator).

(iv) CO2 mass emission rate during performance test (metric tons/hour).

(11) Number of times missing data procedures were used and for which parameter as 

specified in this paragraph (b)(11):

(i) Trona or soda ash (number of months).

(ii) Inorganic carbon contents of trona or soda ash (weeks).

(iii) Process vent flow rate from mine water stripper/evaporator (number of months).

Subpart EE—Titanium Dioxide Production

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) or (b) of this section, as applicable for each titanium 

dioxide production line.

§ 98.316 Data reporting requirements.

(a) If a CEMS is used to measure CO2 emissions, then you must report the relevant 

information required under § 98.36(e)(2)(vi) for the Tier 4 Calculation Methodology and the 

following information in this paragraph (a).
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(1) Identification number of each process line.

(2) Annual consumption of calcined petroleum coke (tons).

(3) Annual production of titanium dioxide (tons).

(4) Annual production capacity of titanium dioxide (tons).

(5) Annual production of carbon-containing waste (tons), if applicable.

(b) If a CEMS is not used to measure CO2 emissions, then you must report the 

information listed in this paragraph (b):

(1) Identification number of each process line.

(2) Annual CO2 emissions from each chloride process line (metric tons/year).

(3) Annual consumption of calcined petroleum coke for each process line (tons).

(4) Annual production of titanium dioxide for each process line (tons).

(5) Annual production capacity of titanium dioxide for each process line (tons).

(6) [Reserved]Calcined petroleum coke consumption for each process line for each 

month (tons).

(7) Annual production of carbon-containing waste for each process line (tons), if 

applicable.

(8) Monthly production of titanium dioxide for each process line (tons).

(9) [Reserved]Monthly carbon content factor of petroleum coke (percent by weight 

expressed as a decimal fraction).

(10) Whether monthly carbon content of the petroleum coke is based on reports from the 

supplier or through self measurement using applicable ASTM standard methods.

(11) Carbon content for carbon-containing waste for each process line (percent by weight 

expressed as a decimal fraction).
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(12) If carbon content of petroleum coke is based on self measurement, the ASTM 

standard methods used.

(13) Sampling analysis results of carbon content of petroleum coke as determined for 

QA/QC of supplier data under § 98.314(d) (percent by weight expressed as a decimal fraction).

(14) Number of separate chloride process lines located at the facility.

(15) The number of times in the reporting year that missing data procedures were 

followed to measure the carbon contents of petroleum coke (number of months); petroleum coke 

consumption (number of months); carbon-containing waste generated (number of months); and 

carbon contents of the carbon-containing waste (number of times during year).

Subpart GG—Zinc Production

In addition to the information required by § 98.3(c), each annual report must contain the 

information specified in paragraphs (a) or (b) of this section, as applicable, for each Waelz kiln 

or electrothermic furnace.

§ 98.336 Data reporting requirements.

(a) If a CEMS is used to measure CO2 emissions, then you must report under this subpart 

the relevant information required for the Tier 4 Calculation Methodology in § 98.36 and the 

information listed in this paragraph (a):

(1) Annual zinc product production capacity (tons).

(2) Annual production quantity for each zinc product (tons).

(3) Annual facility production quantity for each zinc product (tons).

(4) Number of Waelz kilns at each facility used for zinc production.

(5) Number of electrothermic furnaces at each facility used for zinc production.

(b) If a CEMS is not used to measure CO2 emissions, then you must report the 

information listed in this paragraph (b):
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(1) Identification number and annual process CO2 emissions from each individual Waelz 

kiln or electrothermic furnace (metric tons).

(2) Annual zinc product production capacity (tons).

(3) Annual production quantity for each zinc product (tons).

(4) Number of Waelz kilns at each facility used for zinc production.

(5) Number of electrothermic furnaces at each facility used for zinc production.

(6) [Reserved]Annual mass of each carbon-containing input material charged to each kiln 

or furnace (including zinc bearing material, flux materials (e.g., limestone, dolomite), carbon 

electrode, and other carbonaceous materials (e.g.

(7) [Reserved]Carbon content of each carbon-containing input material charged to each 

kiln or furnace (including zinc bearing material, flux materials, and other carbonaceous 

materials) from the annual carbon analysis or from information provided by the material supplier 

for each kiln or furnace (percent by weight, expressed as a decimal fraction).

, coal, coke)) (tons).

(8) Whether carbon content of each carbon-containing input material charged to each kiln 

or furnace is based on reports from the supplier or through self measurement using applicable 

ASTM standard method.

(9) If carbon content of each carbon-containing input material charged to each kiln or 

furnace is based on self measurement, the ASTM Standard Test Method used.

(10) [Reserved]Carbon content of the carbon electrode used in each furnace from the 

annual carbon analysis or from information provided by the material supplier (percent by weight, 

expressed as a decimal fraction).

(11) Whether carbon content of the carbon electrode used in each furnace is based on 

reports from the supplier or through self measurement using applicable ASTM standard method.
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(12) If carbon content of carbon electrode used in each furnace is based on self 

measurement, the ASTM standard method used.

(13) If you use the missing data procedures in § 98.335(b), you must report how the 

monthly mass of carbon-containing materials with missing data was determined and the number 

of months the missing data procedures were used.

Subpart TT—Industrial Waste Landfills

In addition to the information required by § 98.3(c), each annual report must contain the 

following information for each landfill.

§ 98.466 Data reporting requirements.

(a) Report the following general landfill information:

(1) A classification of the landfill as “open” (actively received waste in the reporting 

year) or “closed” (no longer receiving waste).

(2) The year in which the landfill first started accepting waste for disposal.

(3) The last year the landfill accepted waste (for open landfills, enter the estimated year 

of landfill closure).

(4) The capacity (in metric tons) of the landfill.

(5) An indication of whether leachate recirculation is used during the reporting year and 

its typical frequency of use over the past 10 years (e.g

(b) Report the following waste characterization and modeling information:

., used several times a year for the past 10 

years, used at least once a year for the past 10 years, used occasionally but not every year over 

the past 10 years, not used).

(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.
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(2) A description of each waste stream (including the types of materials in each waste 

stream) for which Equation TT–1 of this subpart is used to calculate modeled CH4 generation.

(3) The fraction of CH4 in the landfill gas, F, (volume fraction, dry basis, corrected to 0% 

oxygen) for the reporting year and an indication as to whether this was the default value or a 

value determined through measurement data.

(4) The methane correction factor (MCF) value used in the calculations. If an MCF value 

other than the default of 1 is used, provide 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.

(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.

(2) The method(s) for estimating historical waste disposal quantities and the range of 

years for which each method applies.

(3) If Equation TT–2 of this subpart is used, provide:

(i) [Reserved]The total number of years (N) for which disposal and production data are 

both available.

(ii) The year, of the data used in Equation TT-2 for 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) [Reserved]The average waste disposal factor (WDF) calculated for the waste stream.

(4) If Equation TT–4 of this subpart is used, provide:
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(i) The value of landfill capacity (LFC).

(ii) YrData.

(iii) YrOpen.

(d) For each year of landfilling starting with the “Start Year” (S) and each year thereafter 

up to the current reporting year, report the following information:

(1) The calendar year for which the following data elements apply.

(2) The quantity of waste (WX) disposed of in the landfill (metric tons, wet weight) for 

the specified year for each waste stream identified in paragraph (b) of this section.

(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 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.

(e) Report the following information describing the landfill cover material:

(1) The type of cover material used (as either organic cover, clay cover, sand cover, or 

other soil mixtures).

(2) For each type of cover material used, the 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.

(f) The modeled annual methane generation (GCH4) for the reporting year (metric tons 

CH4) calculated using Equation TT–1 of this subpart.

(g) For landfills without gas collection systems, provide:
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(1) The annual methane emissions (i.e

(2) An indication of whether passive vents and/or passive flares (vents or flares that are 

not considered part of the gas collection system as defined in § 98.6) are present at this landfill.

., the methane generation (MG), adjusted for 

oxidation, calculated using Equation TT–6 of this subpart), reported in metric tons CH4.

(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).