1

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 s ections 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: §98.4662

Appendix A Revisions to Rule Text in Track Changes3
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 p art. 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 t he 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 aft er 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 calenda r 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 whi ch 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 mo nth of the change4
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 s upplier 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 CO 2 , CH 4 , N 2 O, and each fluorinated GHG (as defined in § 98 .6) as follows. (i) Annual emissions (excluding biogenic CO 2 ) aggregated for all GHG from all applicable source categories, expressed in metric tons of CO 2 e calculated using Equation A

– 1 of this subpart. (ii) Annual emissions of biogenic CO 2 aggregated for all applicable source categories, expressed in metric tons. (iii) Annual emissions from each applicable source category, expressed in metric to ns of each applicable GHG listed in paragraphs (c)(4)(iii)(A) through (c)(4)(iii)(E) of this section. (A) Biogenic CO 2 . (B) CO 2 (excluding biogenic CO 2 ). (C) CH 4 . (D) N 2 O.5 (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) In dicate (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 CO 2 e for only those fluorinated GHGs listed i n 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 th e 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 CO 2 , CH 4, N 2 O, 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 CO 2 e calculated using Equ ation A

– 16
of this subpart. For fluorinated GHGs, calculate and report CO 2 e 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 CO 2 e 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 stat ement 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 r eport a second primary NAICS code.7
(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 r eport 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 ad dress 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, a nd report 100 percent ownership by the joint venture or cooperative. , company A owns 40 percent, company B ow ns 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.8
(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

a s 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 facil ity, 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 CO 2 e calculated using Equation A

– 1 of this sub part. You must include biogenic CO 2 emissions from part 75 units in these annual emissions, but exclude biogenic CO 2 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 p art 75 of this chapter to quantify CO 2 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 CO 2, expressed in metric tons (excludin g biogenic CO 2 emissions from part 75 units), aggregated for all applicable source categories.9
(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 CO 2 (excluding biogenic CO 2 emissions from part 75 units). (B) CO 2 . You must include biogenic CO 2 emissions from part 75 units in these totals and exclude biogenic CO 2 emissions from other non

- part 75 units and other source categories. (C) CH 4 . (D) N 2 O. (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,

o wners 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 a cquire, 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 requ irements 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:10
(ii) Supplier data. (iii) Engineering calculations. (iv) Other company records. (2) Requests for extension of the use of best available monito ring 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 monitori ng 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 obt ained 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 unit11

shutdown. Includ e 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 p rocess 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 conta ining 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.12
(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 CO 2 , CH 4, N 2 O, and CO 2 e. (v) For each stationary fuel combustion source that that meets the criteria specified in § 98.36(f) of this part , report A a ny 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 subp arts, 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. Veri fication

(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 comp rehensive 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 ow ner or operator that is required to report GHGs under this part must keep records as specified in this paragraph. R etain all required records for at least 3 years. Except as otherwise provided in this paragraph, R r etain 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 record13
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 ret ained 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.14
(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 a ll 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, q uality 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.15
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 pl an 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 instru mentation 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 re visions

(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 er ror. 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.16
(3) A substantive error is an error that impacts the quantity of GHG emiss ions 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

- d ay 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 exten sion, 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 para meters. 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 CO 2 mass emissions.17
flow rates and provide data for the GHG emissions calculations shall be calibrated prior to April 1, 2010 using the proc edures 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 de vices ( e.g.

(i) All flow meters and other measurement devices that a re 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 o f 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 accur acy 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 sta ndards. 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 measureme nt 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 the18
date on which data collection is required to begin using the measurement device, and the i nitial 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 measure ment 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 manufac turer 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. Excep t 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 consi stent units of measure ( e.g. , gallons/minute, ft 3 /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 transmitter19
calibrations. Calculate the calibration error of each transmitter at each measurement point, using Equation A

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

– 3 of this subpart must be in consistent units of measure ( e.g. , milliamperes, inches of water, psi, degrees). For each transmitter, the CE value at each measurement point shall not exceed 2.0 percent of full

sca le. 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 vici nity 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 measu rement 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 va lues for temperature and/or total pressure, based on20
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
approp riate 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 demonstrat ion 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 specif ic 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 thi s 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 descri bed 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 an d total pressure values to correct the measured flow rates to standard conditions.21
(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 rel ationship(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 suppli er 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 cali bration 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 o f that date, the previous calibration is still active ( i.e.

(6) For units and processes that operate continuously with infrequent outag es, 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 unt il 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 mo nitoring 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 mete r 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 th e 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 installa tion 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 ope rator 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 notificatio n 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 notic e 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 tha n 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 insta ll 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 t hrough 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 av ailable 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 be yond 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 own er 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 a25
process equipment or unit shutdown, or that installation of the measure ment 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 paragra ph 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 subm itted?

(b) For reporting year 2014 and thereaft er, you must enter into verification software specified by the Administrator the data used as inputs to the calculat ion methods specified in Table A

- 8 to Part 98, excluding data required to be reported in the reporting section of each subpart listed in Tab le 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. 126

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)( 15 13 ) 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 used28

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 CH 4 emission factor, activity data for calculating emissions, and unit

- specific emission factor for CH 4 . Y 98.256(f)(12) Only unit

- specific emission factor for N 2 O, units of measure for the unit

- specific N 2 O emission factor, and35

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 dat a 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 CH 4 emission factor, units of measure for unit

- specific CH 4 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 site

specific emissions factor. Y 98.256(j)(2) All. Y 98.256(j)(5) Only CO 2 emission factor. Y 98.256(j)(6) Only CH 4 emission factor. Y 98.256(j)(7) Only carbon emission factor. Y 98.256(j)(8) Only CO 2 emission factor and carbon emission factor. Y 98.256(j)(9) Only CH 4 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 dela yed 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, CH 4 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 CH 4 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 CH 4 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 pow er 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 capac ities 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 Adm inistrator. 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, L

26, 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

- 139

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 com bustion 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 dat a in paragraphs (b) through ( f d ) 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 CO 2 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 CO 2 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 CO 2 mass emissions (including biogenic CO 2 ), and the annual CH 4 , and
N 2 O mass emissions for each type of fuel combusted during the reporting year, expressed in metric tons of each gas and in metric tons of CO 2 e; and (ii) Metric tons of biogenic CO 2 emissions (if applicable). (9) For a unit that uses Tier 4: (i) If the total annual CO 2 mass emissions measured by the CEMS consists entirely of

non - biog enic CO 2 ( i.e. , CO 2 from fossil fuel combustion plus, if applicable, CO 2 from sorbent and/or process CO 2 ), report the total annual CO 2 mass emissions, expressed in metric tons. You are not required to report the combustion CO 2 emissions by fuel type.41
(ii) Report the total annual CO 2 mass emissions measured by the CEMS. If this total includes both biogenic and non

- biogenic CO 2 , separately report the annual non

- biogenic CO 2 mass emissions and the annual CO 2 mass emissions from biomass combustion, each express ed in metric tons. You are not required to report the combustion CO 2 emissions by fuel type. (iii) The annual CH 4 and N 2 O 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 i n metric tons of each gas and in metric tons of CO 2 e. (iv) For each stationary fuel combustion source that meets the criteria specified in paragraph (f) of this section, report A a n 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
CH 4 and N 2 O emissions for each of these fuels, expressed in metric tons of each gas and in metric t ons of CO 2 e . (10) Annual CO 2 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 p aragraph 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 t he 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. If42
this option is selected, the following information shall be reported instead of the information in paragraph (b) of this sec tion: (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 ye ar. (vi) Annual CO 2 mass emissions and annual CH 4 , and N 2 O 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 CO 2 e. If any of the units burn b oth fossil fuels and biomass, report also the annual CO 2 emissions from combustion of all fossil fuels combined and annual CO 2 emissions from combustion of all biomass fuels combined, expressed in metric tons. (vii) The methodology ( i.e. , tier) used to cal culate the CO 2 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 CO 2 mass emissions (i f 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 CO 2 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
separa tely reporting the GHG emissions from the individual units. This monitoring and reporting43
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 exiti ng 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 th e 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 off

gases, 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 station ary fuel combustion units. , a fur nace, 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 CO 2 mass emissions, i.e. (vi) The methodology start date. , Tier 4.

(vii) The methodology end date. (viii) Total annua l CO 2 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
CO 2 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 st ack or duct during the report year, the annual , CO 2 from fossil fuel combustion plus, if applicable, CO 2 from s orbent and/or process CO 2 ) and the annual CO 2 mass emissions from biomass combustion, each expressed in metric tons.44

CH 4 and N 2 O mass emissions from the units sharing the common stack or duct, expressed in metric tons of each gas and in metric tons of CO 2 e. (x) For each stationary fuel combustion source that meets the criteria specified in paragraph (f) of this section, A a n 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 repo rt year , and, for each of these fuels, the annual CH 4 and N 2 O mass emissions from the units sharing the common stack or duct, expressed in metric tons of each gas and in metric tons of CO 2 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 sup ply line is diverted to either: A flare; or another stationary fuel combustion unit (or units), including units that use a CO 2 mass emissions calculation method in part 75 of this chapter; or a chemical or industrial process (where it is used
as a raw mate rial 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 mea sured (or obtained from gas billing records) at the main supply line prior to performing the GHG45
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 divert ed 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 t he 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 th rough 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 thi s 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 reporti ng year. (v) The methodology used to calculate the CO 2 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 CO 2 mass emissions from combustion of all fossil fuels and annual CO 2 emis sions from combustion of all biomass fuels from the units served by the common pipe, expressed in metric tons.46
(vii) Annual CO 2 mass emissions and annual CH 4 and N 2 O emissions from each fuel type for the units served by the common pipe, expressed in metri c tons of each gas and in metric tons of CO 2 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 lar ge 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 th e 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 small47
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, CP00 1, etc. (ii) Annual CO 2 emissions at each monitored location, expressed in both short tons and metric tons. Separate reporting of biogenic CO 2 emissions under § 98 .3(c)(4)(ii) and § 98 .3(c)(4)(iii)(A) is opt ional only for the 2010 reporting year, as provided in § 98 .3(c)(12). ) that are reported under §75.64 of this chapter.

(iii) Annual CH 4 and N 2 O 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 CO 2 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 CO 2 mass emissions. (vi) Methodology start date. (vii) Methodology end date. (viii) Acid Rain Program indicator. (ix) Annual CO 2 mass emissions from the combustion of biomass, expressed in metric tons of CO 2 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 CO 2 mass emissions calculation methods provided in § 98 .33(a)(5), you shall report the f ollowing 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 u nder §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 CO 2 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 CO 2 emissions at each monitored location, across all fuel types, expressed in metric tons of CO 2 e. (G) Annual heat input from each type of fuel listed in Table C

– 2 o f this subpart that was combusted during the reporting year, expressed in mmBtu. (H) Annual CH 4 and N 2 O 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

o therwise provided in § 98 .33(c)(4)(ii)(D)), expressed in metric tons CO 2 e.49
(I) Annual CO 2 mass emissions from the combustion of biomass, expressed in metric tons
CO 2 e, except where the reporting provisions of § § 98 .3(c)(12)(i) through (c)(12)(iii) are
im plemented 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 chapt er: (A) Each type of fuel combusted during the reporting year. (B) Methodology used to calculate the CO 2 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

meas urements. (F) The total annual CO 2 emissions at each monitored location, expressed in metric tons of CO 2 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 CH 4 and N 2 O 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 CO 2 e. (I) An nual CO 2 mass emissions from the combustion of biomass, expressed in metric tons
CO 2 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 verifica tion 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 mo nitoring systems provided in § 98 .33(a)(5). (iii) Are not in the Acid Rain Program, but are required to monitor and report CO 2 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 CO 2 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 aggregat ed 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, T t he total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during each month of the reportin g year. Express the51
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) F or each stationary fuel combustion source that meets the criteria specified in paragraph (f) of this section, T t he high heat values used in the CO 2 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 f or 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, I i f Equation C

– 2c of this subpart is used to calculate CO 2 mass emissions, report the total quantity ( i.e.

(E) For each HHV us ed in the CO 2 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 deter mine 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 ar e 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, T t he 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 a pplicable, 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 th is section, T t he 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, m olecular 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, k g 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 kg

mole. , daily, weekly, monthly, semiannually, once per fuel lot).

(D) The total number of valid carbon content determinations and, if applicable, molecular weight determinations made d uring 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, T t he annual average HHV, when measured HHV data, rather than a53

default HHV from Table C

– 1 of this subpart, are used to calculate CH 4 and N 2 O 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 calibration s 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 molecu lar 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 dat es 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 CO 2 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 CO 2 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 qua lity 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 CO 2 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 Eq uation C

– 11 of this subpart. (ix) For units that combust both fossil fuel and biomass, when biogenic CO 2 is determined according to § 98 .33(e)(2), you shall report the following additional information, as applicable: (A) The annual volume of CO 2 emitted fr om the combustion of all fuels, i.e. (B) The annual volume of CO 2 emitted from the combustion of fossil fuels, , V total , in scf. i.e.

(C) The annual volume of CO 2 emitted from the combustion of biomass, , V ff , in scf. If more than one type of fossil fuel was combusted, report the combustion volume of CO 2 for each fuel separat ely 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, T t he carbon

- based F

- factor used in Equation C

– 13 of this subpart, for each type of fossil fuel combusted, in scf CO 2 per mmBtu. , V bio , in scf.55
(E) For each stationary fuel combustion source that meets the criteria specified in paragraph (f) of this section, T t he annual average HHV value used in E quation 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, T t he total quantity of each type of fossil fuel combusted during the reporting year, in lb, gallons, or scf, as appropriate. (G) Annual biogenic CO 2 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 CO 2 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 CO 2 mass emissions from MSW combustion, in metric tons. , if the biogenic fraction of the CO 2 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 CO 2 emissions from a unit that co

- fires biogenic fuels (or partly

- biogenic fuels, including tires if you are electing t o report biogenic CO 2 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
CO 2 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 u sed to calculate CO 2 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 CO 2 emissions. (iii) An explanation of how sorbent usag e is quantified. (iv) An explanation of how company records are used to quantify fossil fuel consumption in units that uses CEMS to quantify CO 2 emissions and combusts both fossil fuel and biomass. (v) An explanation of how company records are used to meas ure steam production, when it is used to calculate CO 2 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 paragra ph (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 th e 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

I n addition to the information required by § 98 .3(c), each annual report must contain the information specified in paragraphs (a) through ( l n ) of this section at the facility level. § 98.56 Data reporting requirements.

(a) Annual process N 2 O emissions from adipic acid production (metric tons). (b) [Reserved] Annual adipic acid production (tons). (c) [Reserved] Annual adipic acid production during which N 2 O abatement technology (located after the test point) is operating (tons). (d) Annual process N 2 O 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 dest ruction). (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 pro duction (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 a dipic acid production unit.58
(1) [Reserved] Emission factor (lb N 2 O/ton adipic acid). (2) Test method used for performance test. (3) [Reserved] Production rate per test run during performance test (tons/hr). (4) N 2 O concentration per test run during performan ce test (ppm N 2 O). (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
N 2 O 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 me thod. (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 N 2 O 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 CF 4 /metric ton Al)/(mV/cell day)), potline overvoltage (mV/cell day), current efficiency (%).) (3) Smelter

- specific slope coefficients (or overvoltage emission factors) an d t T he 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 CO 2 - specific information for prebake cells: (1) Annual anode consumption if using the method in § 98.63(g)

. (2) Annual CO 2 emissions from the smelter. (f) The following CO 2 - specific information for Sderberg cells: (1) Annual paste consumption if using the m ethod in § 98.63(g)

. (2) Annual CO 2 emissions from the smelter. (g) [Reserved] Smelter

- specific inputs to the CO 2 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. , point

feed 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 CO 2 emissions, then you must report the relevant informa tion 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 feed stock). (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 CO 2 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 carbo n 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 gas eous 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 feedstoc k, 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) CO 2 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 CO 2 consumed in urea production. ( 14 ) Annual ammonia product ion (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 ann ual 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 CO 2 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 CO 2 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 non

calcined MgO in clinker for each kiln (as wt

- fractions). (7) Method used to determine non

- calcined CaO and non

- calcined MgO in clinker. (8) [Reserved] Quarterly fraction of total CaO, total MgO, non

- calcined CaO and non

calcined MgO in CKD not recycled to the kiln for each kiln (as wt

- fractions). ( 9) Method used to determine non

- calcined CaO and non

- calcined MgO in CKD. (10) [Reserved] Monthly kiln

- specific clinker CO 2 emission factors for each kiln (metric
tons CO 2 /metric ton clinker produced). (11) Quarterly kiln

- specific CKD CO 2 emission factors for each kiln (metric tons
CO 2 /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 of Annual consumption of raw kiln feed or annual consumption of each raw material (dry basis)

. (14) Number of times missing data procedures were used to determine the following information: (i) Clinker production (number of months). (ii) Carbonate contents of clinker (number of months). (iii) Non

- calcine d 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 mon ths). (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 CO 2 emission factor for the facility, averaged across all kilns (metric tons CO 2 /metric ton clinker produced). (18) Annual average CKD CO 2 emission factor for the facility, averaged across all kilns (metric tons CO 2 /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 CO 2 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 pr ocess CO 2 emissions (in metric tons) from each EAF used for the production of any ferroalloy product identified in § 98 .110. (2) Annual process CH 4 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K

– 1 of th is subpart (metric tons). (3) Identification number of each EAF. (e) If a CEMS is not used to measure CO 2 process emissions, and the carbon mass balance procedure is used to determine CO 2 emissions according to the requirements in § 98 .113(b), then you mus t report the following information specified in paragraphs (e)(1) through (e)(7) of this section. (1) Annual process CO 2 emissions (in metric tons) from each EAF used for the production of any ferroalloy identified in § 98 .110 (metric tons). (3) Identifica tion number for each material. (4) [Reserved] Annual material quantity for each material included for the calculation of annual process CO 2 emissions for each EAF. (5) [Reserved] Annual average of the carbon content determinations for each material included for the calculation of annual process CO 2 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 section included f or the calculation of annual process CO 2 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 informat ion 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)(v ii) 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 sectio n 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 product ion 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
separ ately 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 tra nsformation 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

- vent

specific emissio n calculation factor method , report the method s used to estimate emissions from equipment leaks.

(b) Reporting for mass balance approac h

. For processes whose emissions are determined using the mass

- balance approach under § 98 .123(b), you must report the information listed in67
paragraphs (b)(1) through (b)(13) of this section for each process on an annual basis. Identify and separately repo rt 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 th eir 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 f ormula 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 in to 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

- cont aining 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 d emonstrated 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 efficie ncy 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 by

product.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 use d 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. Fluorin ated 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) t T he 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 th ese excess emissions would be reflected in70

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
G HG whose destruction the facility reflects in § 98.123, in accordance with § 98.124(g)(1)(i) through (iv). . By March 31, 2 012 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) throu gh (f)(4) of this section. This report is one

time 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 chang es, 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 o f the fluorinated GHG fed into the destruction device. . Each fluorinated
gas pr oduction 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 t hat vents residual fluorinated GHGs from containers must report the following for each fluorinated GHG vented:

(2) [Reserved] If applicable, the heel fact or 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 3 0, 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 inclu de 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) o f 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 facil ity

- wide CO 2 e emissions but are not required to be reported separately. Calculation and reporting of CO 2 e . You must report the total fluorinated GHG emissions covered by this subpart, expressed in metric tons of CO 2 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 CO 2 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 struc ture 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 th e 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 fl uorinated 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 CO 2 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 CO 2 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 CO 2 e, 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 CO 2 emissions, then you must report under this subpart the relevant information required under § 98 .36 for the Tier 4 Calculation Methodology and the following informat ion 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 CO 2 emissions from continuous glass melting furnaces, and process CO 2 emissions are calculated according to the procedures specified in §74

98 .143(b), then you must r eport the following information as specified in paragraphs (b)(1) through (b)(9) of this section: (1) Annual process emissions of CO 2 (metric tons) for each continuous glass melting furnace and for all furnaces combined. (2) Annual quantity of each carbona te

- 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 carbo nate

- 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 an alyzed. (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 CO 2 . (7) Method used to determine fraction of calcination. (8) Total number of contin uous 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 m elting 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 facil ity 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 me tric tons) of materials other than HCFC

– 22 and HFC

– 23 ( i.e.

(5) The method for tracking startups, shutdowns, an d 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 gen erated 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 r equired 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 effic iency 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 fe d 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 th is 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 s pecified in paragraphs (a) or (b) of this section, as appropriate, and paragraphs (c) through and ( d e ) of this section: § 98.166 Data reporting requirements.

(a) If a CEMS is used to measure CO 2 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 CO 2 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 CO 2 emissions, then you must report the following information for each hydrogen production process unit: (1) U nit identification number and annual CO 2 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 f eedstocks). (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 CO 2 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 CO 2 collected and tr ansferred 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 co ke 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 fo r 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) Uni t identification number and annual CO 2 emissions (in metric tons). (b) If a CEMS is used to measure CO 2 emissions, then you must report T t he annual production quantity for the production unit (in metric tons) for taconite pellets, coke, sinter, iron, and r aw steel. (c) If a CEMS is used to measure CO 2 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 CO 2 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 CO 2 emissions, you mus t report the following information for each process: (1) [Reserved] The carbon content of each process input and output used to determine
CO 2 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 t ype in gallons), and the annual mass (in metric tons) of each other process inputs and outputs used to determine CO 2 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 pr ocess units for which CO 2 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 CO 2 emissions were determined using Equations Q

- 1 through Q

- 7 of this section, calculated as specified in Equation Q

- 9 of this section.
Fuel = � ∑ F g , i ∗ MW i MVC n i = 1 ∗ 0

. 001 + F l , i ∗ ρ l , i ∗ 0

. 001 + F s , 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. F g,i = Annual volume of gaseous fuel combusted (“ (F g )” in Equations Q

- 1, Q

- 4 and Q

- 7 of this section ) for each process (scf). MW i = Mole cular 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. F l,i = Annual volume of the liquid fuel combusted (“ (F l )” included in Equation Q

- 1 of this section ) for each process unit (gallons). F s,i = Annual mass of the solid fuel combusted (“ (F s )” in Equation Q

- 1 of this section ) for each process unit (metric tons). ρ l,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 + Steel in n i = 1 + Ore + Ot h er ) (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 ma ss 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 o f 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). Steel in = 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 = ( ∑ P + R + Steel out + Slag + Coke + Sinter + Iron + NM n i = 1 ) ( 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). Steel out = 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.

CF avg = � ∑ F g , i ∗ MW i MVC n i = 1 ∗ C gf , i ∗ 0

. 001 + F l , i ∗ C lf , i ∗ 0

. 001 + F s , i ∗ C sf � Fuel (Eq. Q

- 12)
Where:83

CF avg = 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. C gf,i = Average carbon content of the gaseous fuel used in each process, from the fuel analysis results (kg C per kg of fuel). C lf,i = Carbon content of the liquid fuel us ed in each process, from the fuel analysis results (kg C per gallon of fuel. C sf = 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 Equati on Q

- 13 of this section.
CI avg = � ∑ NFI i ∗ C NFIi n i = 1 � NFI (Eq. Q

- 13)
Where:

CI avg = 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 Q

10. NFI i = Annual mass of each non

- fuel input used in Equation Q

- 10 (metric tons). C NFIi = 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 specifie d in Equation Q

- 14 of this section.
CP avg = � ∑ Product i ∗ C Pi n i = 1 � Products (Eq. Q

- 14)84

Where:

CP avg = 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. Product i = Annual mass of each product or byproduct used in Equation Q

- 11 of this section (metric tons). C p,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 met hod in § 98 .173(b)(2) to determine
CO 2 emissions, you must report the following information for each process: (1) The measured average hourly CO 2 emission rate during the test (in metric tons per hour). (2) [Reserved] The average hourly feed or production r ate (as applicable) during the test (in metric tons per hour). (3) [Reserved] The site

- specific emission factor (in metric tons of CO 2 per metric ton of feed or production, as applicable). (4) [Reserved] The annual feed or production rate (as applicable) used to estimate annual
CO 2 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 (Pe troleum 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 app licable. (a) If a CEMS is used to measure CO 2 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 CO 2 emissions, and you measure CO 2 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) Ide ntification number of each smelting furnace. (2) Annual process CO 2 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 fo r the calculation of annual process CO 2 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 CO 2 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 CO 2 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 annua l 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 CO 2 emissions, then you must report under this subpart the relevant information required by § 98 .36 and the informatio n 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 inventori es 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 CO 2 emissions, then you must report the information list ed in paragraphs (b)(1) through ( 17 18 ) of this section. (1) Annual CO 2 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 byp roduct/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 produce d 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 (mon ths) or the chemical composition of lime products sold (months). (17) Indicate whether CO 2 was used on

- site ( i.e.

(i) T he annual amount of CO 2 captured for use in the on

- site process. , for use in a purification process). If CO 2 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 CO 2 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 reporti ng requirements.

(a) Annual CO 2 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

— Nitr ic Acid Production

In addition to the information required by § 98 .3(c), each annual report must contain the information specified in paragraphs (a) through ( p q ) of this section. § 98.226 Data reporting requirements.

(a) Train identification number. (b) An nual process N 2 O emissions from each nitric acid train (metric tons). (c) [Reserved] (d) [Reserved] Annual nitric acid production from each nitric acid train during which N 2 O 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 N 2 O 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 aci d 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 ca lculated 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 N 2 O/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) N 2 O concentration per test run during pe rformance test (ppm N 2 O). (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 re quested Administrator approval for an alternative method of determining
N 2 O 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 secti on 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 N 2 O 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)( 11 13 ) 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 carbon

containing feedstocks. (3) Annual CO 2 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 th rough X

– 3 of this subpart ( i.e.

( 5) A nnual 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
t T he 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) Identifi cation 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 rep ort 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 w hy 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 X

1, 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)( 8 10 ) 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 CO 2 e missions from each stack and the combined CO 2 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 stationar y combustion unit (or group of combustion units monitored with a single CO 2 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

- g as 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 CH 4 and N 2 O emissions as specified in paragraphs (b)(5)(i) through (b)(5)(iv) of th is section. (i) The CH 4 and N 2 O emissions from each stack that is monitored with a CO 2 CEMS, expressed in metric tons of each gas and in metric tons of CO 2 e. For each stack provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off

- gas from the petrochemical process unit. (ii) The combined CH 4 and N 2 O emissions from all stationary combustion units, expressed in metric tons of each gas and in metric tons of CO 2 e. (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 comb ustion 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 s ources 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, fol low 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 CO 2 , CH 4 , and N 2 O annual emissions for each flare, expressed in metric tons of each pollutant emitted. (5) A des cription of the method used to calculate the CO 2 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/kg

mole), 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 CO 2 concentration (volume or mole pe rcent), the number of carbon containing compounds other than CO 2 in the flare gas stream, and for each of the carbon containing compounds other than CO 2 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 millio n (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 higher97
heating value of the flare gas were determined using standard c onditions 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/mmsc f), 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 fla re) 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

crac king unit, traditional fluid coking unit, or catalytic reforming unit). (3) Maximum rated throughput of the unit, in bbl/stream day. (4) The calculated CO 2 , CH 4 , and N 2 O annual emissions for each unit, expressed in metric tons of each pollutant emitted.98
(5 ) A description of the method used to calculate the CO 2 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 CO 2 annual emi ssions as measured by the CEMS (unadjusted to
remove CO 2 combustion emissions associated with additional units, if present) and the process
CO 2 emissions as calculated according to § 98 .253(c)(1)(ii). Report the CO 2 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, %C O 2 , 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, %O 2 , %O oxy , %CO 2 , and %CO. (9) If you use Equation Y

– 7b of this subpart, the annual average flow rate of inlet air and
oxygen - enriched air, %N 2,oxy , and %N 2,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 CH 4 emissions. If you use a unit

- specific emission factor for CH 4 , report the unit

- specific emission factor for CH 4 , 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 N 2 O emissions. If you use a unit

- specific emission factor for N 2 O, report the unit

- specific emission factor for N 2 O, the units of measure for the unit

- specific fact or, the activity data for calculating emissions ( e.g.

(13) If you use Equation Y

– 11 of this subpart, the number of regeneration cycle s 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 § 9 8 .253(c). (5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, also report the calculated annual CO 2 , CH 4 , and N 2 O emissions for each unit, expressed in metric tons of each pollutant emitted, and the applicable equati on 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 applicabl e). (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 indication100

of the method used to calculate CO 2 annual emissions for the sulfur recovery plant ( e.g.

(3) The calculated CO 2 annual emissions for each sulfur recovery plant, expressed in metric tons. The calculated annual CO 2 emissions fr om sour gas sent off

- site for sulfur recovery, expressed in metric tons. , CO 2 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 unde r § 98.253(f)(2) and (3). Indicate whether a correction for CO 2 emissions in the tail gas was used in Equation Y

– 12 of this subpart . If so, then report : (i) T t he 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 the only. (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 CO 2 annu al emissions as measured by the CEMS and the annual process CO 2 emissions calculated according to § 98 .253(f)(1). Report the CO 2 annual emissions101
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 CO 2 , CH 4 , and N 2 O annual emissions for each unit, expressed in metric tons of each pollutant emitted. (4) A description of the method us ed to calculate the CO 2 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 CO 2 annual emissions a s measured by the CEMS and the annual process CO 2 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 CH 4 emissions. If you use a unit

- specific emission factor fo r CH 4 , the unit

- specific emission factor for CH 4 , the units of measure for the unit

- specific factor, the activity data for102
calculating emissions ( e.g.

(8) Indicate whether you use a measured value, a unit

- specific emission factor, or a default emission factor for N 2 O emissions. If you use a unit

- specific emission factor for N 2 O, report the unit

- specific emission factor for N 2 O, 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), and report the basis for the factor.

e.g.

(j) For asphalt blowing operati ons, 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) emiss ions from the unit. (4) The calculated annual CO 2 and CH 4 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 CO 2 emission factor used and the basis for the value

. (6) If you use Equation Y

– 15 of this subpart, the basis for the CH 4 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 Eq uation Y

– 16b of this subpart, the CO 2 emission factor used and the basis for its value the CO 2 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 th e CH 4 emission factor used and the basis for the value

. (k) For delayed coking units, the owner or operator shall report: (1) The cumulative annual CH 4 emissions (in metric tons of CH 4 ) for all delayed coking units at the facility. (2) A description of the method used to calculate the CH 4 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 ve ssel : 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 CF 4 /kg

- mole gas, wet basis). the unfilled distance from the top of the drum, in feet ) , the molar volume conversion factor (in s cf/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 a ssociated 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 CO 2 , CH 4 , and N 2 O 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 CH 4 emissions (in metri c tons of CH 4 ) 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 CH 4 emissions (in metric tons of each pollutant emitted) for all equipment leak sou rces. (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 cumulat ive annual CH 4 emissions (in metric tons of CH 4 ) 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 CH 4 emissions (in metric tons of CH 4 ) for storage tanks used to process unstabilized crude oil or a statement that the fa cility 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 CH 4 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 CH 4 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 CH 4 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 generati on rate data, if you did not use Equation Y

– 23. (p) For loading operations, the owner or operator shall report: (1) The cumulative annual CH 4 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 volume107
percent or greater, and the type of vessel s (barge, tanker, marine vessel, etc.) in which the each type of mater ial 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 ea ch 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 measuremen t records by origin, (as listed in Table Z

– 1 to this subpart) (tons). (e) If you use a CEMS to measure CO 2 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 ph osphoric acid process line. (2) The annual CO 2 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 CE MS 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 CO 2 emissions from each wet

- process phosphoric acid proce ss 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 m issing 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 CO 2 (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 CO 2 emissions from phosphoric acid production facility (metric tons). Subpart AA

— Pulp and Paper Manufacturing

In addition to the inform ation required by § 98.3(c) and the applicable information required by § 98.36, each annual report must contain the information in paragraphs (a) through ( k m ) of this section as applicable: § 98.276 Data reporting requirements.109
(a) Annual emissions of CO 2 , biogenic CO 2 , CH 4 , biogenic CH 4 N 2 O, and biogenic N 2 O (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) A nnual mass of the spent liquor solids combusted (short tons per year), and b B asis 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 CO 2 , CH 4 , or N 2 O, used in Equation
AA

– 1 of this subpart (kg CO 2 , CH 4 , or N 2 O 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 CaCO 3 used for the reporting year (metric tons per year) used in Equation A A

– 3 of this subpart. (i) [Reserved] Make

- up quantity of Na 2 CO 3 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, individu ally 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 CO 2 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 ste am), 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 CO 2 emissions, you must report under this subpart the relevant information required for the Tier 4 Calc ulation 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 no t used to measure process CO 2 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 product ion 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 co ntent of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM standard method. (6) [Reserved] CO 2 emissions factor calculated for each month (metric tons CO 2 /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.112
(a) If a CEMS is used to measure CO 2 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) An nual 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 CO 2 emissions, then yo u must report the information listed in this paragraph (b): (1) Identification number of each manufacturing line. (2) Annual process CO 2 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 m anufacturing 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 CO 2 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 as113
described in Equation CC

– 2 of this subpart, or a site

- speci fic emission factor method as described in Equations CC

– 3 through CC

– 5 of this subpart. (9) Number of manufacturing lines located used to produce soda ash. (10) If you produce soda ash using the liquid alkaline feedstock process and use the site

specific e mission 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 CO 2 concentration dur ing performance test (percent CO 2 ). (iii) CO 2 emission factor (metric tons CO 2 /metric tons of process vent flow from mine water stripper/evaporator). (iv) CO 2 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 (nu mber 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 CO 2 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 thi s paragraph (a).114
(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 CO 2 emissions, then you must report the information listed in this paragraph (b): (1) Identification number of each process line. (2) Annual CO 2 emissions from each chlori de 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 pr ocess 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 measuremen t using applicable ASTM standard methods. (11) Carbon content for carbon

- containing waste for each process line (percent by weight expressed as a decimal fraction).115
(12) If carbon content of petroleum coke is based on self measurement, the ASTM standard me thods 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 (numbe r 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 infor mation 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 CO 2 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 product ion 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 produ ction. (b) If a CEMS is not used to measure CO 2 emissions, then you must report the information listed in this paragraph (b):116
(1) Identification number and annual process CO 2 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 pro duction. (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 sel f 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 carbo n 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 o n reports from the supplier or through self measurement using applicable ASTM standard method.117
(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 pro cedures 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 requi rements.

(a) Report the following general landfill information: (1) A classification of the landfill as “open” (actively rece ived 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 landfil l 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 Indus trial Solid Waste (not otherwise listed)”) for which Equation TT

– 1 of this subpart is used to calculate modeled CH 4 generation.118
(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 CH 4 generation. (3) The fraction of CH 4 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 determine d 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 l andfill 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 secti on, 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:119
(i) The value of landfill capacity (L FC). (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 app ly. (2) The quantity of waste (W X ) 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 (DOC X ) value (mass fraction) for the specif ied 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
DOC x 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 (GCH 4) for the reporting year (metric tons
CH 4 ) calculated using Equation TT

– 1 of this subpart. (g) For landfills without gas collection systems, provide:120
(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 CH 4 .

(h) For landfills with gas collection systems, in addition to th e reporting requirements in paragraphs (a) through (f) of this section, you must report according to § 98 .346(i).