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

Corrects cross-reference.
                                       X
98.246(a)(11)(iii)
(iii) An explanation of why an alternative to the methods listed in §§98.244(b)(4)(i) through (xii) is needed.

(iii) An explanation of why an alternative to the methods listed in §§98.244(b)(4)(i) through (xiv) is needed.

Yes
Corrects reference
                                       X
98.246(b)(2)
(2) For CEMS used on stacks for stationary combustion units, report the relevant information required under §98.36 for the Tier 4 calculation methodology. Section 98.36(b)(9)(iii) does not apply for the purposes of this subpart.
(2) For CEMS used on stacks that include emissions from stationary combustion units that burn any amount of off-gas from the petrochemical process, report the relevant information required under §98.36(c)(2) and (e)(2)(vi) for the Tier 4 calculation methodology. Sections 98.36(c)(2)( ii) and (c)(2)(ix) do not apply for the purposes of this subpart.
Yes
Clarifies CEMS reporting requirement to align more closely with procedures in e-GGRT and corrects cross-reference. Final rule corrects typo.
                                       X
98.246(b)(3)
(3) For CEMS used on stacks that are not used for stationary combustion units, report the information required under §98.36(e)(2)(vi).
(3) For CEMS used on stacks that do not include emissions from stationary combustion units, report the information required under §98.36(b)(6), (b)(7), and (e)(2)(vi).
Yes
Clarifies CEMS reporting requirement to align more closely with procedures in e-GGRT. Final rule corrects typo.
                                       X
98.246(b)(4)
(4) The CO2 emissions from each stack and the combined CO2 emissions from all stacks (except flare stacks) that handle process vent emissions and emissions from stationary combustion units that burn process off-gas for the petrochemical process unit. For each stationary combustion unit (or group of combustion units monitored with a single CO2 CEMS) that burns petrochemical process off-gas, provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off-gas from the petrochemical process unit.
(4) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) or (3) of this section, provide an estimate based on engineering judgment of the fraction of the total CO2 emissions that results from CO2 directly emitted by the petrochemical process unit plus CO2 generated by the combustion of off-gas from the petrochemical process unit.
Yes
See final preamble text for explanation
                                       X
98.246(b)(5)
(5) For stationary combustion units that burn process off-gas from the petrochemical process unit, report the information related to CH4 and N2O emissions as specified in paragraphs (b)(5)(i) through (b)(5)(iv) of this section.
(i) The CH4 and N2O emissions from each stack that is monitored with a CO2 CEMS, expressed in metric tons of each gas and in metric tons of CO2 e. For each stack provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off-gas from the petrochemical process unit.
(ii) The combined CH4 and N2O emissions from all stationary combustion units, expressed in metric tons of each gas and in metric tons of CO2 e.
(iii) The quantity of each type of fuel used in Equation C - 8 in §98.33(c) for each stationary combustion unit or group of units (as applicable) during the reporting year, expressed in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.
(iv) The HHV (either default or annual average from measured data) used in Equation C - 8 in §98.33(c) for each stationary combustion unit or group of combustion units (as applicable).
(5) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) of this section, report the CH4 and N2O emissions expressed in metric tons of each gas. For each CEMS monitoring location, provide an estimate based on engineering judgment of the fraction of the total CH4 and N2O emissions that is attributable to combustion of off-gas from the petrochemical process unit.
(i)[Reserved]
(ii)[Reserved]
(iii)[Reserved]
(iv)[Reserved]

See proposal preamble (77 FR 19802)
                                       X
98.246(b)(6)
(6) ID or other appropriate descriptor of each stationary combustion unit that burns process off-gas.
(6) [Reserved]

See proposal preamble (77 FR 19802)
                                       X
98.246(c)(4)
(4) Name and annual quantity of each feedstock.
(4) Name and annual quantity of each feedstock (metric tons).

Clarifies units of measure for reporting requirement
                                       X
98.247(b)
(b) If you comply with the mass balance methodology in §98.243(c), then you must retain records of the information listed in paragraphs (b)(1) through (b)(3) of this section.
(1) Results of feedstock or product composition determinations conducted in accordance with §98.243(c)(4).
(2) Start and end times and calculated carbon contents for time periods when off-specification product is produced, if you comply with the alternative methodology in §98.243(c)(4) for determining carbon content of feedstock or product.
(3) A part of the monitoring plan required under §98.3(g)(5), record the estimated accuracy of measurement devices and the technical basis for these estimates.
(b) If you comply with the mass balance methodology in §98.243(c), then you must retain records of the information listed in paragraphs (b)(1) through (b)(4) of this section.
(1) Results of feedstock or product composition determinations conducted in accordance with §98.243(c)(4).
(2) Start and end times for time periods when off-specification product is produced, if you comply with the alternative methodology in §98.243(c)(4) for determining carbon content of product.
(3) As part of the monitoring plan required under §98.3(g)(5), record the estimated accuracy of measurement devices and the technical basis for these estimates.
Yes
Corrects a reference and reduces recordkeeping requirements when the alternative methodology in 98.234 (c)(4) is used. Final rule corrects typo in 98.247(b)(3).
                                       X
98.248
Product, as used in §98.243, means each of the following carbon-containing outputs from a process: the petrochemical, recovered byproducts, and liquid organic wastes that are not incinerated onsite. Product does not include process vent emissions, fugitive emissions, or wastewater.
Product, as used in §98.243, means each of the following carbon-containing outputs from a process: the petrochemical, recovered byproducts, and liquid organic wastes that are not combusted onsite. Product does not include process vent emissions, fugitive emissions, or wastewater.

The definition of product has been revised to provide consistency with other subparts of this rule.
                                       Y
98.252(a)
(a) .... For CH4 and N2O emissions from combustion of fuel gas, use the applicable procedures in 98.33 (c) for the same tier methodology that was used for calculating CO2 emissions. (Use the default CH4 and N2O emission factors for "Petroleum (All fuel types in Table C-1)" in Table C-2 of this part.  For Tier 3...
(a) .... For CH4 and N2O emissions from combustion of fuel gas, use the applicable procedures in 98.33(c ) for the same tier methodology that was used for calculating CO2 emissions. (Use the default CH4 and N2O emission factors for "Fuel Gas" in Table C-2 of this part. For Tier 3....

See proposal preamble (77 FR 19802)
                                       Y
98.252(i)
(i) CO2 emissions from non-merchant hydrogen production process units (not including hydrogen produced from catalytic reforming units) under this subpart.  You must follow the calculation methodologies, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of subpart P of this part.
(i) CO2 emissions from non-merchant hydrogen production process units (not including hydrogen produced from catalytic reforming units) following the calculation methodologies, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of subpart P of this part.

Clarifies requirement
                                       Y
98.253(b)(2)
EmFCH4 = Default CH4 emission factor for "PetroleumProducts" from Table C-2 of Subpart C of this part (General Stationary Fuel Combustion Sources) (kg CH4/MMBtu)
EmFCH4 = Default CH4 emission factor for "Fuel Gas" from Table C-2 of Subpart C of this part (General Stationary Fuel Combustion Sources) (kg CH4/MMBtu)

See proposal preamble (77 FR 19802)
                                       Y
98.253(b)(3)
EmFN2O = Default N2O emission factor for "PetroleumProducts" from Table C-2 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg N2O/MMBtu).
EmFN2O = Default N2O emission factor for "Fuel Gas" from Table C-2 of subpart C of this part (General Stationary Fuel Combustion Sources) (kg N2O/MMBtu).

See proposal preamble (77 FR 19802)
                                       Y
98.253(f)(2)
(2) Flow measurement. If you have a continuous flow monitor on the sour gas feed to the sulfur recovery plant, you must use the measured flow rates when the monitor is operational to calculate the sour gas flow rate. If you do not have a continuous flow monitor on the sour gas feed to the sulfur recovery plant, you must use engineering calculations, company records, or similar estimates of volumetric sour gas flow.
(2) Flow measurement. If you have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use the measured flow rates when the monitor is operational to calculate the sour gas flow rate. If you do not have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use engineering calculations, company records, or similar estimates of volumetric sour gas flow.

Clarifies requirement
                                       Y
98.253(f)(3)
(3) Carbon content. If you have a continuous gas composition monitor capable of measuring carbon content on the sour gas feed to the sulfur recovery plant or if you monitor gas composition for carbon content on a routine basis, you must use the measured carbon content value. Alternatively, you may develop a site-specific carbon content factor using limited measurement data or engineering estimates or use the default factor of 0.20.
(3) Carbon content. If you have a continuous gas composition monitor capable of measuring carbon content on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, or if you monitor gas composition for carbon content on a routine basis, you must use the measured carbon content value. Alternatively, you may develop a site-specific carbon content factor using limited measurement data or engineering estimates or use the default factor of 0.20.
Yes
Clarifies requirement. Final rule corrects typo.
                                       Y
98.253(f)(4)
(4) Calculate the CO2 emissions from each sulfur recovery plant using Equation Y - 12 of this section.
Where:
FSG = Volumetric flow rate of sour gas feed (including sour water stripper gas) to the sulfur recovery plant (scf/year).
MFC = Mole fraction of carbon in the sour gas to the sulfur recovery plant (kg-mole C/kg-mole gas); default = 0.20.
(4) Calculate the CO2 emissions from each on-site sulfur recovery plant and for sour gas sent off-site for sulfur recovery using Equation Y - 12 of this section.
Where:
FSG = Volumetric flow rate of sour gas (including sour water stripper gas) fed to the sulfur recovery plant or the sour gas feed sent off-site for sulfur recovery (scf/year).
MFC = Mole fraction of carbon in the sour gas fed to the sulfur recovery plant or the sour gas feed sent off-site for sulfur recovery (kg-mole C/kg-mole gas); default = 0.20.

See proposal preamble (77 FR 19802)
                                       Y
98.253(j)
(j) For each process vent not covered in paragraphs (a) through (i) of this section that can reasonably be expected to contain greater than 2 percent by volume CO2 or greater than 0.5 percent by volume of CH4 or greater than 0.01 percent by volume (100 parts per million) of N2O, calculate GHG emissions using the Equation Y - 19 of this section. You must use Equation Y - 19 of this section to calculate CH4 emissions for catalytic reforming unit depressurization and purge vents when methane is used as the purge gas or if you elected this method as an alternative to the methods in paragraphs (f), (h), or (k) of this section.
(j) For each process vent not covered in paragraphs (a) through (i) of this section that can reasonably be expected to contain greater than 2 percent by volume CO2 or greater than 0.5 percent by volume of CH4 or greater than 0.01 percent by volume (100 parts per million) of N2O, calculate GHG emissions using Equation Y - 19 of this section. You must also use Equation Y - 19 of this section to calculate CH4 emissions for catalytic reforming unit depressurization and purge vents when methane is used as the purge gas, CH4 emissions if you elected to use the method in paragraph (i)(1) of this section, and CO2 and/or CH4 emissions, as applicable, if you elected this method as an alternative to the methods in paragraphs (f), (h), or (k) of this section.
Yes
See proposal preamble (77 FR 19802). Final rule corrects typo.
                                       Y
98.253(k)
(k) For uncontrolled blowdown systems, you must calculate CH4 emissions either using the methods for process vents in paragraph (j) of this section regardless of the CH4concentration or using Equation Y20  of this section. Blowdown systems where the uncondensed gas stream is routed to a flare or similar control device is considered to be controlled and is not required to estimate emissions under this paragraph (k).
(k) For uncontrolled blowdown systems, you must calculate CH4 emissions either using the methods for process vents in paragraph (j) of this section regardless of the CH4 concentration or using Equation Y-20 of this section. Blowdown systems where the uncondensed gas stream is routed to a flare or similar control device are considered to be controlled and are not required to estimate emissions under this paragraph (k).
Yes
Corrects typographical error in reference to equation Y-20. Final rule corrects typo.
                                       Y
98.253(m)
(m) For storage tanks, except as provided in paragraph (m)(4) of this section, calculate CH4 emissions using the applicable methods in paragraphs (m)(1) through (m)(3) of this section.
(m) For storage tanks, except as provided in paragraph (m)(3) of this section, calculate CH4 emissions using the applicable methods in paragraphs (m)(1) and (m)(2) of this section.

Corrects cross-reference
                                       Y
98.256(f)(6)
(6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology, the CO2 annual emissions as measured by the CEMS (unadjusted to remove CO2 combustion emissions associated with additional units, if present) and the process CO2 emissions as calculated according to §98.253(c)(1)(ii). Report the CO2 annual emissions associated with sources other than those from the coke burn-off in the applicable subpart (e.g., subpart C of this part in the case of a CO boiler).
(6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology, the CO2 annual emissions as measured by the CEMS (unadjusted to remove CO2 combustion emissions associated with additional units, if present) and the process CO2 emissions as calculated according to §98.253(c)(1)(ii). Report the CO2 annual emissions associated with sources other than those from the coke burn-off in accordance with the applicable subpart (e.g., subpart C of this part in the case of a CO boiler).

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

See proposal preamble (77 FR 19802)
                                       Y
98.256(h)(2)
(2) Maximum rated throughput of each independent sulfur recovery plant, in metric tons sulfur produced/stream day, a description of the type of sulfur recovery plant, and an indication of the method used to calculate CO2 annual emissions for the sulfur recovery plant (e.g., CO2 CEMS, Equation Y - 12, or process vent method in §98.253(j)).
(2) For each on-site sulfur recovery plant, the maximum rated throughput (metric tons sulfur produced/stream day), a description of the type of sulfur recovery plant, and an indication of the method used to calculate CO2 annual emissions for the sulfur recovery plant (e.g., CO2 CEMS, Equation Y - 12, or process vent method in §98.253(j)).

See proposal preamble (77 FR 19802)
                                       Y
98.256(h)(3)
(3) The calculated CO2 annual emissions for each sulfur recovery plant, expressed in metric tons. The calculated annual CO2 emissions from sour gas sent off-site for sulfur recovery, expressed in metric tons.
(3) The calculated CO2 annual emissions for each on-site sulfur recovery plant, expressed in metric tons. The calculated annual CO2 emissions from sour gas sent off-site for sulfur recovery, expressed in metric tons.

See proposal preamble (77 FR 19802)
                                       Y
98.256(h)(4)
(4) If you use Equation Y - 12 of this subpart, the annual volumetric flow to the sulfur recovery plant (in scf/year), the molar volume conversion factor (in scf/kg-mole), and the annual average mole fraction of carbon in the sour gas (in kg-mole C/kg-mole gas).
(4) If you use Equation Y - 12 of this subpart, the annual volumetric flow to the on-site and off-site sulfur recovery plant (in scf/year), the molar 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).

See proposal preamble (77 FR 19802)
                                       Y
98.256(h)(5)
(5) If you recycle tail gas to the front of the sulfur recovery plant, indicate whether the recycled flow rate and carbon content are included in the measured data under §98.253(f)(2) and (3). Indicate whether a correction for CO2 emissions in the tail gas was used in Equation Y - 12. If so, then report the value of the correction, the annual volume of recycled tail gas (in scf/year) and the annual average mole fraction of carbon in the tail gas (in kg-mole C/kg-mole gas). Indicate whether you used the default (95%) or a unit specific correction, and if used, report the approach used.
(5) If you recycle tail gas to the front of an on-site sulfur recovery plant, indicate whether the recycled flow rate and carbon content are included in the measured data under §98.253(f)(2) and (3). Indicate whether a correction for CO2 emissions in the tail gas was used in Equation Y - 12. If so, then report the value of the correction, the annual volume of recycled tail gas (in scf/year) and the annual average mole fraction of carbon in the tail gas (in kg-mole C/kg-mole gas). Indicate whether you used the default (95%) or a unit specific correction, and if a unit specific correction is used, report the approach used.

See proposal preamble (77 FR 19802)
                                       Y
98.256(h)(6)
(6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology, the CO2 annual emissions as measured by the CEMS and the annual process CO2 emissions calculated according to §98.253(f)(1). Report the CO2 annual emissions associated with fuel combustion  subpart C of this part (General Stationary Fuel Combustion Sources).
(6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology, the CO2 annual emissions as measured by the CEMS and the annual process CO2 emissions calculated according to §98.253(f)(1). Report the CO2 annual emissions associated with fuel combustion in accordance with subpart C of this part (General Stationary Fuel Combustion Sources).

Clarifies reporting requirements
                                       Y
98.256(j) (10)
(None)
(10) If you use Equation Y-19 of this subpart, the relevant information required under paragraph (l)(5) of this section.

See proposal preamble (77 FR 19802)
                                       Y
98.256(k)(4)
(4) For each set of coking drums that are the same dimensions: The number of coking drums in the set, the height and diameter of the coke drums (in feet), the cumulative number of vessel openings for all delayed coking drums in the set, the typical venting pressure (in psig), void fraction (in cf gas/cf of vessel), and the mole fraction of methane in coking gas (in kg-mole CF4/kg-mole gas, wet basis).
(4) For each set of coking drums that are the same dimensions: The number of coking drums in the 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 CH4/kg-mole gas, wet basis).

Corrects typographical error (CF4 to CH4)
                                       Y
98.256(k)(6)
(None)
(6) If you use Equation Y-19 of this subpart, the relevant information required under paragraph (l)(5) of this section for each set of coke drums or vessels of the same size.

See proposal preamble (77 FR 19802)
                                       Y
98.256(o)(4)(vi)
(vi) If you did not use Equation Y - 23, the tank-specific methane composition data and the gas generation rate data used to estimate the cumulative CH4 emissions for storage tanks used to process unstabilized crude oil.
(vi) If you did not use Equation Y - 23, the tank-specific methane composition data and the annual gas generation volume (scf/yr) used to estimate the cumulative CH4 emissions for storage tanks used to process unstabilized crude oil.

Clarifies reporting requirements
                                       Y
98.256(o)(5), (6), (7)
(5) The method used to calculate the reported storage tank emissions for storage tanks processing unstabilized crude oil.
(6) The quantity of unstabilized crude oil received during the calendar year (in MMbbl), the average pressure differential (in psi), and the mole fraction of CH4 in vent gas from the unstabilized crude oil storage tank, and the basis for the mole fraction.
(7) The tank-specific methane composition data and the gas generation rate data, if you did not use Equation Y - 23.
(5) [Reserved]
(6) [Reserved]
(7) [Reserved]

Removes duplicate reporting requirements.
                                       Z
98.263(b)(1)(ii)
(ii) If your process measurement provides the CO2 emissions directly as an output...
CO2 n,i = Carbon dioxide emissions of a grab sample batch of phosphate rock by origin i obtained during month n (percent by weight, expressed as a decimal fraction).
(ii) If your process measurement provides the CO2 content directly as an output...
CO2 n,i = Carbon dioxide content of a grab sample batch of phosphate rock by origin i obtained during month n (percent by weight, expressed as a decimal fraction).

See proposal preamble (77 FR 19802)
                                       Z
98.264(a)
(a) You must obtain a monthly grab sample of phosphate rock directly from the rock being fed to the process line before it enters the mill using one of the following methods. You may conduct the representative bulk sampling using a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists (AFPC) (P.O. Box 1645, Bartow, Florida 33831, (863) 534 - 9755, http://afpc.net, paul.mcafee@mosaicco.com). If phosphate rock is obtained from more than one origin in a month, you must obtain a sample from each origin of rock or obtain a composite representative sample.
(a) You must obtain a monthly grab sample of phosphate rock directly from the rock being fed to the process line before it enters the mill using one of the following methods. You may conduct the representative bulk sampling using a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists (AFPC). If phosphate rock is obtained from more than one origin in a month, you must obtain a sample from each origin of rock or obtain a composite representative sample.

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

Deletes outdated contact information
                                       Z
98.265(a)
(a) For each missing value of the inorganic carbon content of phosphate rock or carbon dioxide (by origin), you must use the appropriate default factor provided in Table Z - 1 this subpart. Alternatively, you must determine a substitute data value by calculating the arithmetic average of the quality-assured values of inorganic carbon contents of phosphate rock of origin i from samples immediately preceding and immediately following the missing data incident. You must document and keep records of the procedures used for all such estimates.
(a) For each missing value of the inorganic carbon content of phosphate rock (by origin), you must use the appropriate default factor provided in Table Z - 1 of this subpart. Alternatively, the you must determine substitute data value by calculating the arithmetic average of the quality-assured values of inorganic carbon contents of phosphate rock of origin i (see Equation Z - 1 of this subpart) from samples immediately preceding and immediately following the missing data incident. If no quality-assured data on inorganic carbon contents of phosphate rock of origin i are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for inorganic carbon contents for phosphate rock of origin i obtained after the missing data period.
A complete record of all measured parameters used in the GHG emissions calculations is required.  Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter must be used in the calculations as specified in paragraphs (a) and (b) of this section.
(a) For each missing value of the inorganic carbon content or CO2 content of phosphate rock (by origin), you must use the appropriate default factor provided in Table Z - 1 of this subpart. Alternatively,  you must determine a substitute data value by calculating the arithmetic average of the quality-assured values of inorganic carbon contents or CO2 contents of phosphate rock of origin i (see Equation Z - 1a or Z-1b of this subpart) from samples immediately preceding and immediately following the missing data incident. If no quality-assured data on inorganic carbon contents or CO2 contents of phosphate rock of origin i are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for inorganic carbon contents or CO2 contents for phosphate rock of origin i obtained after the missing data period.

Correction; clarifies the general requirement for missing data, removes a duplicate paragraph, clarifies the data element of inorganic carbon content may also be represented by CO2 content, and corrects the equation reference.
                                       Z
98.266(a)
(a) Annual phosphoric acid production by origin (as listed in Table Z - 1 to this subpart) of the phosphate rock (tons).
(a) Annual phosphoric acid production, by origin of the phosphate rock (tons).

Removes a reference to Table Z-1. The reporting element could have a place of origin other than those listed in Table Z-1
                                       Z
98.266(b)
(b) Annual phosphoric acid permitted production capacity (tons)
(b) Annual phosphoric acid production capacity (tons)

See proposal preamble (77 FR 19802)
                                       Z
98.266(d)
(d) Annual phosphate rock consumption from monthly measurement records by origin, (as listed in Table Z - 1 to this subpart) (tons).
(d) Annual phosphate rock consumption from monthly measurement records by origin (tons).

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

Clarifies reporting requirements
                                       Z
98.266(f)(6)
(6) Monthly mass of phosphate rock consumed by origin, (as listed in Table Z - 1 of this subpart) in production for each wet-process phosphoric acid process line (tons).
(6) Monthly mass of phosphate rock consumed, by origin, in production for each wet-process phosphoric acid process line (tons).

Clarifies reporting requirements
                                       Z
98.266(f)(8)
(8) Number of times missing data procedures were used to estimate phosphate rock consumption (months) and inorganic carbon contents of the phosphate rock (months).
(8) Number of times missing data procedures were used to estimate phosphate rock consumption (months), inorganic carbon contents of the phosphate rock (months), and CO2 contents of the phosphate rock (months).

Adds reporting requirement for missing data procedures
                                       Z
98.267(a)
(a) Monthly mass of phosphate rock consumed by origin (as listed in Table Z - 1 of this subpart) (tons).
(a) Monthly mass of phosphate rock consumed by origin (tons).

Removes a reference to Table Z-1. The reporting element could have a place of origin other than those listed in Table Z-1
                                       Z
98.26(c )
(c) Documentation of the procedures used to ensure the accuracy of monthly phosphate rock consumption by origin, (as listed in Table Z - 1 of this subpart).
(c) Documentation of the procedures used to ensure the accuracy of monthly phosphate rock consumption by origin.

Removes a reference to Table Z-1. The reporting element could have a place of origin other than those listed in Table Z-1
                                      AA
98.273(a)(3)
(3) Calculate biogenic CO2 emissions and emissions of CH4 and N2O from biomass using measured quantities of spent liquor solids fired, site-specific HHV, and default or site-specific emissions factors, according to Equation AA - 1 of this section:
***
(Variable from Equation AA-1:)
(EF) = Default or site-specific emission factor for CO2, CH4, or N2O, from Table AA - 1 of this subpart (kg CO2, CH4, or N2O per mmBtu).
(3) Calculate biogenic CO2 emissions and emissions of CH4 and N2O from biomass using measured quantities of spent liquor solids fired, site-specific HHV, and default emissions factors, according to Equation AA - 1 of this section:
***
(Variable from Equation AA-1:)
(EF) = Default emission factor for CO2, CH4, or N2O, from Table AA - 1 of this subpart (kg CO2, CH4, or N2O per mmBtu).

See proposal preamble (77 FR 19802)
                                      AA
98.276(e)
(e) The default or site-specific emission factor for CO2, CH4, or N2O, used in Equation AA - 1 of this subpart (kg CO2, CH4, or N2O per mmBtu).
(e) The default emission factor for CO2, CH4, or N2O, used in Equation AA - 1 of this subpart (kg CO2, CH4, or N2O per mmBtu).

Harmonize with change made to 98.273(a)(3)
                                      AA
98.276(k)
(k) Annual production of pulp and/or paper products produced (metric tons).
(k) Total annual production of unbleached virgin chemical pulp produced onsite during the reporting year in air-dried metric tons per year. This total annual production value is the sum of all kraft, semichemical, soda, and sulfite pulp produced onsite, prior to bleaching, through all virgin pulping lines. Do not include mechanical pulp or secondary fiber repulped for paper production in the virgin pulp production total.
Yes
See final preamble text for explanation
                                      AA
Tables AA-1 & AA-2
See Tables AA-1 and AA-2 in the current rule file.
See Appendix A for changes to Table AA-1 and AA-2

See proposal preamble (77 FR 19802)
                                      BB
98.282(a)
(a) CO2 and CH4 process emissions from all silicon carbide process units or furnaces combined.
(a) CO2 process emissions from all silicon carbide process units or furnaces combined.

See proposal preamble (77 FR 19802)
                                      BB
98.283
Introductory paragraph
98.283 Calculating GHG Emissions.
You must calculate and report the annual process CO2 emissions from each silicon carbide process unit or production furnace using the procedures in either paragraph (a) or (b) of this section.  You must determine CH4 process emissions in accordance with the procedures specified in paragraph (d) of this section.
98.283 Calculating GHG Emissions.
You must calculate and report the combined annual process CO2 emissions from all silicon carbide process units and production furnaces using the procedures in either paragraph (a) or (b) of this section.

See proposal preamble (77 FR 19802)
                                      BB
98.283(a)
(a) Calculate and report under this subpart the process CO2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).
(a) Calculate and report under this subpart the combined annual process CO2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology specified in §98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

Harmonizing change with 98.283 introductory paragraph.
                                      BB
98.283(b)
(b) Calculate and report under this subpart the process CO2 emissions using the procedures in paragraphs (b)(1) and (b)(2) of this section.
(b) Calculate and report under this subpart the combined annual process CO2 emissions using the procedures in paragraphs (b)(1) and (b)(2) of this section.

Harmonizing change with 98.283 introductory paragraph.
                                      BB
98.283(b)(2)
(2) Use Equation BB - 2 of this section to calculate annual CO2 process emissions from all silicone carbide production:
(2) Calculate annual CO2 process emissions from the silicon carbide production facility according to Equation BB-2 of this section:

Corrects misspelling and clarifies requirement
                                      BB
98.283(b)(2)
Tn = Petroleum coke consumption in month n(tons)
Tn = Petroleum coke consumption in calendar month n(tons)

Clarifies equation term
                                      BB
98.283(d)
(d) You must calculate annual process CH4 emissions from all silicon carbide production combined using Equation BB - 3 of this section:
Eq. BB-3
None

See proposal preamble (77 FR 19802)
                                      BB
98.286(b)
(b) If a CEMS is not used to measure process CO2 emissions, you must report the information listed in this paragraph (b) for all furnaces combined:
(b) If a CEMS is not used to measure process CO2 emissions, you must report the information in paragraph (b)(1) through (b)(8) of this section for all silicon carbide process units or production furnaces combined:

Correction for consistency with 40 CFR 98.282.
                                      DD
98.304(c)(1)
(1) Ensure that cylinders returned to the gas supplier are consistently weighed on a scale that is certified to be accurate and precise to within 2 pounds of the scale's capacity and is periodically recalibrated per the manufacturer's specifications. Either measure residual gas (the amount of gas remaining in returned cylinders) or have the gas supplier measure it. If the gas supplier weighs the residual gas, obtain from the gas supplier a detailed monthly accounting, within +- 2 pounds, of residual gas amounts in the cylinders returned to the gas supplier.
(1) Ensure that cylinders returned to the gas supplier are consistently weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer's specifications. Either measure residual gas (the amount of gas remaining in returned cylinders) or have the gas supplier measure it. If the gas supplier weighs the residual gas, obtain from the gas supplier a detailed monthly accounting, within +- 2 pounds, of residual gas amounts in the cylinders returned to the gas supplier.

See proposal preamble (77 FR 19802)
                                      DD
98.304(c)(2)
(2) Ensure that cylinders weighed for the beginning and end of year inventory measurements are weighed on a scale that is certified to be accurate to within 2 pounds of the scale's capacity and is periodically recalibrated per the manufacturer's specifications. All scales used to measure quantities that are to be reported under §98.306 must be calibrated using calibration procedures specified by the scale manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer.
(2) Ensure that cylinders weighed for the beginning and end of year inventory measurements are weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer's specifications. All scales used to measure quantities that are to be reported under §98.306 must be calibrated using calibration procedures specified by the scale manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer.

See proposal preamble (77 FR 19802)
                                      FF
98.320(b)(1)
(1) Each ventilation well or shaft, including both those wells and shafts where gas is emitted and those where gas is sold, used onsite, or otherwise destroyed (including by flaring).
(1) Each ventilation system shaft or vent hole, including both those points where mine ventilation air is emitted and those where it is sold, used onsite, or otherwise destroyed (including by ventilation air methane (VAM) oxidizers).

See proposal preamble (77 FR 19802)
                                      FF
98.320(b)(2)
(2) Each degasification system well or shaft, including degasification systems deployed before, during, or after mining operations are conducted in a mine area. This includes both those wells and shafts where gas is emitted, and those where gas is sold, used onsite, or otherwise destroyed (including by flaring).
(2) Each degasification system well or gob gas vent hole, including degasification systems deployed before, during, or after mining operations are conducted in a mine area. This includes both those wells and vent holes where coal bed gas is emitted, and those where the gas is sold, used onsite, or otherwise destroyed (including by flaring).

See proposal preamble (77 FR 19802)
                                      FF
98.322(b)
(b) You must report CH4 destruction from systems where gas is sold, used onsite, or otherwise destroyed (including by flaring).
(b) You must report CH4 destruction from systems where gas is sold, used onsite, or otherwise destroyed (including by VAM oxidation and by flaring).

See proposal preamble (77 FR 19802)
                                      FF
98.322(d)
(d) You must report under this subpart the CO2 emissions from coal mine gas CH4 destruction occurring at the facility, where the gas is not a fuel input for energy generation or use ( e.g., flaring).
(d) You must report under this subpart the CO2 emissions from coal mine gas CH4 destruction occurring at the facility, where the gas is not a fuel input for energy generation or use (e.g., flaring and VAM oxidation).

See proposal preamble (77 FR 19802)
                                      FF
98.323(a)
V = Volumetric flow rate for the quarter (cfm) based on sampling or a flow rate meter. If a flow rate meter is used and the meter automatically corrects for temperature and pressure, replace "520°R/T x P/1 atm" with "1".
V = Volumetric flow rate for the quarter (acfm) based on sampling or a flow rate meter. If a flow rate meter is used and the meter automatically corrects to standard temperature and pressure, then use scfm and replace "520°R/T x P/1 atm" with "1".

Clarifies an equation term
                                      FF
98.323(a)
MCF = Moisture correction factor for the measurement period, volumetric basis.

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

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

Corrects subscript errors
                                      FF
98.323(a)
(fH2O) = Moisture content of the methane emitted during the measurement period, volumetric basis (cubic feet water per cubic feet emitted gas).
(fH2O) = Moisture content of the CH4 emitted during the measurement period, volumetric basis (cubic feet water per cubic feet emitted gas).

Corrects subscript errors
                                      FF
98.323(a)
P = Pressure at which flow is measured (atm) for the quarter. The annual average barometric pressure from the nearest NOAA weather service station may be used as a default.
P = Absolute pressure at which flow is measured (atm) for the quarter. The annual average barometric pressure from the nearest NOAA weather service station may be used as a default.

See proposal preamble (77 FR 19802)
                                      FF
98.323(a)(2)
(2) Values of V, C, T, P, and (fH2O), if applicable  must be based on measurements taken at least once each quarter with no fewer than 6 weeks between measurements. If measurements are taken more frequently than once per quarter, then use the average value for all measurements taken. If continuous measurements are taken, then use the average value over the time period of continuous monitoring.
(2) Values of V, C, T, P, and (fH2O), if applicable must be based on measurements taken at least once each quarter with no fewer than 6 weeks between measurements. If measurements are taken more frequently than once per quarter, then use the average value for all measurements taken. If continuous measurements are taken, then use the average value over the time period of continuous monitoring.

Corrects subscript errors and typographical error.
                                      FF
98.323(b) Equation FF-3
T
Ti

Corrects subscript errors
                                      FF
98.323(b)
Vi= Measured volumetric flow rate for the days in the week when the degasification system is in operation at that monitoring point, based on sampling or a flow rate meter (cfm). If a flow rate meter is used and the meter automatically corrects for temperature and pressure, replace "520°R/Tix Pi/1 atm" with "1".
Vi= Measured volumetric flow rate for the days in the week when the degasification system is in operation at that monitoring point, based on sampling or a flow rate meter (acfm). If a flow rate meter is used and the meter automatically corrects to standard temperature and pressure, then use scfm and replace "520°R/Tix Pi/1 atm" with "1".

Clarification of equation term
                                      FF
98.323(b)
fH2O
fH2O

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

Clarifies an equation term
                                      FF
98.323(b)(1)
(1) Values of V, C, T, P, and (fH2O), if applicable...
(1) Values of V, C, T, P, and (fH2O), if applicable...

Corrects subscript errors
                                      FF
98.323(b)(2)
CH4D
(CH4D)i.j

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

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

Clarifies terminology and equation reference
                                      FF
98.323 (c ) Equation FF-6

Corrects equation term
                                      FF
98.324(b)
(b) For CH4 liberated from ventilation systems, determine whether CH4 will be monitored from each ventilation well and shaft, from a centralized monitoring point, or from a combination of the two options. Operators are allowed flexibility for aggregating emissions from more than one ventilation well or shaft, as long as emissions from all are addressed, and the methodology for calculating total emissions documented. Monitor by one of the following options:
(b) For CH4 liberated from ventilation systems, determine whether CH4 will be monitored from each ventilation shaft and vent hole, from a centralized monitoring point, or from a combination of the two options. Operators are allowed flexibility for aggregating emissions from more than one ventilation point, as long as emissions from all are addressed, and the methodology for calculating total emissions documented. Monitor by one of the following options:

Clarifies rule text.
                                      FF
98.324(c)(2)
(2) Collect weekly (once each calendar week, with at least three days between measurements) or more frequent samples, for all degasification wells and gob gas vent holes. Determine weekly or more frequent flow rates, methane concentration, temperature, and pressure from these degasification wells and gob gas vent holes. Methane composition should be determined either by submitting samples to a lab for analysis, or from the use of methanometers at the degasification well site. Follow the sampling protocols for sampling of methane emissions from ventilation shafts, as described in §98.324(b)(1). You must record the date of sampling, flow, temperature, pressure, and moisture measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection.
(2) Collect weekly (once each calendar week, with at least three days between measurements) or more frequent samples, for all degasification wells and gob gas vent holes. Determine weekly or more frequent flow rates, methane concentration, temperature, and pressure from these degasification wells and gob gas vent holes. Methane composition should be determined either by submitting samples to a lab for analysis, or from the use of methanometers at the degasification monitoring site. Follow the sampling protocols for sampling of methane emissions from ventilation shafts, as described in §98.324(b)(1). You must record the date of sampling, flow, temperature, pressure, and moisture measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection.

Clarifies rule text.
                                      FF
98.326(a)
(a) Quarterly CH4 liberated from each ventilation monitoring point (CH4Vm), (metric tons CH4).
(a) Quarterly CH4 liberated from each ventilation monitoring point, (metric tons CH4).

Clarifies rule text
                                      FF
98.326(f)
(f) Quarterly volumetric flow rate for each ventilation monitoring point (scfm), date and location of each measurement, and method of measurement (quarterly sampling or continuous monitoring), used in Equation FF - 1 of this subpart.
(f) Quarterly volumetric flow rate for each ventilation monitoring point and units of measure (scfm or acfm), date and location of each measurement, and method of measurement (quarterly sampling or continuous monitoring), used in Equation FF - 1 of this subpart.

Harmonizes reporting requirement with equations.
                                      FF
98.326(h)
(h) Weekly volumetric flow rate used to calculate CH4 liberated from degasification systems (cfm) and method of measurement (sampling or continuous monitoring), used in Equation FF - 3 of this subpart.
(h) Weekly volumetric flow rate used to calculate CH4 liberated from degasification systems and units of measure (acfm or scfm), and method of measurement (sampling or continuous monitoring), used in Equation FF - 3 of this subpart.

Harmonizes reporting requirement with equations
                                      FF
98.326(i)
(i) Quarterly CEMS CH4 concentration (%) used to calculate CH4 liberated from degasification systems (average from daily data), or quarterly CH4 concentration data based on results from weekly sampling data) (C).
(i) Quarterly CH4 concentration (%) used to calculate CH4 liberated from degasification systems and if the data is based on CEMS or weekly sampling.

Includes the basis of the concentration data in the report.
                                      FF
98.326(j)
(j) Weekly volumetric flow rate used to calculate CH4 destruction for each destruction device and each point of offsite transport (cfm).
(j) Weekly volumetric flow rate used to calculate CH4 destruction for each destruction device and each point of offsite transport, and units of measure (acfm or scfm).

Harmonizes reporting requirement with equations.
                                      FF
98.326(o)
(o) Temperatures (°R), pressure (atm), and moisture content used in Equation FF - 1 and FF - 3 of this subpart, and the gaseous organic concentration correction factor, if Equation FF - 9 was required.
(o) Temperatures (°R), pressure (atm), moisture content, and the moisture correction factor (if applicable) used in Equation FF - 1 and FF - 3 of this subpart; and the gaseous organic concentration correction factor, if Equation FF - 9 was required.

See proposal preamble (77 FR 19802)
                                      FF
98.326(r)
(r) Identification information and description for each well and shaft, indication of whether the well or shaft is monitored individually, or as part of a centralized monitoring point. Note which method (sampling or continuous monitoring) was used.
(r) Identification information and description for each well, shaft, and vent hole, including paragraphs (r)(1) through (r)(3) of this section:
(1) Indication of whether the well, shaft, or vent hole is monitored individually, or as part of a centralized monitoring point. Note which method (sampling or continuous monitoring) was used.
(2)  Start date and close date of each well, shaft, and vent hole.
(3)  Number of days the well, shaft, or vent hole was in operation during the reporting year.

See proposal preamble (77 FR 19802)
                                      FF
98.326(t)
No current requirement
(t) Mine Safety and Health Administration (MSHA) identification for this coal mine

See proposal preamble (77 FR 19802)
                                      HH
98.340(a)
(a) This source category applies to municipal solid waste (MSW) landfills that accepted waste on or after January 1, 1980.
(a) This source category applies to municipal solid waste (MSW) landfills that accepted waste on or after January 1, 1980, unless all three of the following conditions apply.
(1) The MSW landfill did not receive waste on or after January 1, 2013.
(2) The MSW landfill had CH4 generation as determined using Equation HH-5 and, if applicable, Equation HH-7 of this subpart of less than 1,190 metric tons of CH4 in the 2013 reporting year.
(3) The owner or operator of the MSW landfill was not required to submit an annual report under any requirement of this part in the in any reporting year prior to 2013.
Yes
See final preamble text for explanation
                                      HH
98.343(a)(1) Equation HH-1
DOC = Degradable organic carbon from Table HH-1 of this subpart or measurement data, if available [fraction (metric tons C/metric ton waste)].
DOC = Degradable organic carbon from Table HH-1 of this subpart [fraction (metric tons C/metric ton waste)].

See proposal preamble (77 FR 19802)
                                      HH
98.345
Equation HH-1,
F = Fraction by volume of CH4 in landfill gas from measurement data on a dry basis, if available (fraction); default is 0.5.
F = Fraction by volume of CH4 in landfill gas from measurement data for the current reporting year, if available (fraction, dry basis, corrected to 0%oxygen); otherwise, use the default of 0.5.

See proposal preamble (77 FR 19802)
                                      HH
98.343(b)(1) Equation HH-4
(C)n
(CCH4)n

Corrects equation term
                                      HH
98.343(b)(1) Equation HH-4
N = Total number of measurement periods in a year. Use daily averaging periods for a continuous monitoring system and N=365 (or N = 366 for leap years). For weekly sampling, as provided in paragraph (b)(2) of this section, use N=52.
N = Total number of measurement periods in a year. Use daily averaging periods for a continuous monitoring system and N=365 (or N = 366 for leap years). For monthly sampling, as provided in paragraph (b)(2) of this section, use N=12.

See proposal preamble (77 FR 19802)
                                      HH
HH-4
0.0423 = Density of CH4 lb/cfm at 520°R or 60 degrees Fahrenheit and 1 atm.
0.0423	= Density of CH4 lb/cf at 520°R or 60 degrees Fahrenheit and 1 atm.

Corrects typographical error
                                      HH
98.343(b)(2)(i)
(i) Continuously monitor gas flow rate and determine the cumulative volume of landfill gas each week  and the cumulative volume of landfill gas each year that is collected and routed to a destruction device (before any treatment equipment). Under this option, the gas flow meter is not required to automatically correct for temperature, pressure, or, if necessary, moisture content. If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content, you must determine these parameters as specified in paragraph (b)(2)(iii) of this section.
(i) Continuously monitor gas flow rate and determine the cumulative volume of landfill gas each month  and the cumulative volume of landfill gas each year that is collected and routed to a destruction device (before any treatment equipment). Under this option, the gas flow meter is not required to automatically correct for temperature, pressure, or, if necessary, moisture content. If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content, you must determine these parameters as specified in paragraph (b)(2)(iii) of this section.

Harmonizing change to accommodate monthly sampling of CH4 concentration
                                      HH
98.343(b)(2)(ii)
(ii) Determine the CH4 concentration in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar week, there must be at least three days between measurements.
(ii) Determine the CH4 concentration in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar month; if only one measurement is made each calendar month, there must be at least fourteen days between measurements.

Harmonizing change to accommodate monthly sampling of CH4 concentration
                                      HH
98.343(b)(2)(iii)(A)
(A) Determine the temperature and pressure in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar week, there must be at least three days between measurements.
(A) Determine the temperature and pressure in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar month; if only one measurement is made each calendar month, there must be at least fourteen days between measurements.

Harmonizing change to accommodate monthly sampling of CH4 concentration
                                      HH
98.343(b)(2)(iii)(B)
(B) If the CH4 concentration is determined on a dry basis and flow is determined on a wet basis or CH4 concentration is determined on a wet basis and flow is determined on a dry basis, and the flow meter does not automatically correct for moisture content, determine the moisture content in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar week, there must be at least three days between measurements.
(B) If the CH4 concentration is determined on a dry basis and flow is determined on a wet basis or CH4 concentration is determined on a wet basis and flow is determined on a dry basis, and the flow meter does not automatically correct for moisture content, determine the moisture content in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar month; if only one measurement is made each calendar month, there must be at least fourteen days between measurements.

Harmonizing change to accommodate monthly sampling of CH4 concentration
                                      HH
98.343(c )(1) (Eq. HH-5)
OX = Oxidation fraction.  Use the default value of 0.1 (10%).
OX = Oxidation fraction. Use the appropriate oxidation fraction default value from Table HH-4 of this subpart.

See proposal preamble (77 FR 19802)
                                      HH
98.343(c )(3)(i)
(Eq. HH-6)

See proposal preamble (77 FR 19802)
                                      HH
98.343(c )(3)(i)
(Eq. HH-6)
(None)
N = Number of landfill gas measurement locations (associated with a destruction device or gas sent off-site). If a single monitoring location is used to monitor volumetric flow and CH4 concentration of the recovered gas sent to one or multiple destruction devices, then N=1.

Harmonizing with changes to Equation HH-6 for multiple measurement locations and/or multiple destruction devices
                                      HH
98.343(c )(3)(i)
(Eq. HH-6)
R = Quantity of recovered CH4 from Equation HH-4 of this section (metric tons).
Rn = Quantity of recovered CH4 from Equation HH-4 of this section for the n[th] measurement location (metric tons).

Harmonizing with changes to Equation HH-6 for multiple measurement locations and/or multiple destruction devices
                                      HH
98.343(c )(3)(i)
(Eq. HH-6)
OX = OX = Oxidation fraction.  Use the default value of 0.1 (10%).
OX = Oxidation fraction. Use the appropriate oxidation fraction default value from Table HH-4 of this subpart.

See preamble text for explanation
                                      HH
98.343(c )(3)(i)
(Eq. HH-6)
DE = Destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use DE = 1.
DEn = Destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99) for the n[th] measurement location. If the gas is transported off-site for destruction, use DE = 1. If the volumetric flow and CH4 concentration of the recovered gas is measured at a single location providing landfill gas to multiple destruction devices (including some gas destroyed on-site and some gas sent off-site for destruction), calculate DEn as the arithmetic average of the DE values determined for each destruction device associated with that measurement location.

Harmonizing with changes to Equation HH-6 for multiple measurement locations and/or multiple destruction devices
                                      HH
98.343(c )(3)(i)
(Eq. HH-6)

fDest = Fraction of hours the destruction device was operating (annual operating hours / 8760 hours per year). If the gas is destroyed in a back-up flare (or similar device) or if the gas is transported off-site for destruction, use fDest = 1.
fDest,n = Fraction of hours the destruction device associated with the n[th] measurement location was operating during active gas flow calculated as the annual operating hours for the destruction device divided by the annual hours flow was sent to the destruction device as measured at the nth measurement location. If the gas is transported off-site for destruction, use fDest,n= 1. If the volumetric flow and CH4 concentration of the recovered gas is measured at a single location providing landfill gas to multiple destruction devices (including some gas destroyed on-site and some gas sent off-site for destruction), calculate fDest,n as the arithmetic average of the fDest values determined for each destruction device associated with that measurement location.
Yes
Harmonizing with changes to Equation HH-6 for multiple measurement locations and/or multiple destruction devices and clarifies equation term to more accurately reflect operating hours of the gas collection system. See final preamble text.
                                      HH
98.343(c )(3)(ii)
(Eq. HH-7)

See proposal preamble (77 FR 19802)
                                      HH
98.343(c )(3)(ii)
(Eq. HH-8)




Dest
c
f
DE
R
f
CE
R












1
Re
R


See proposal preamble (77 FR 19802)
                                      HH
98.343(c )(3)(ii)
(Eq. HH-8)
(None)
N = Number of landfill gas measurement locations (associated with a destruction device or gas sent off-site). If a single monitoring location is used to monitor volumetric flow and CH4 concentration of the recovered gas sent to one or multiple destruction devices, then N=1.

Harmonizing with changes to Equation HH-8 for multiple measurement locations and/or multiple destruction devices
                                      HH
98.343(c )(3)(ii)
(Eq. HH-8)
R = Quantity of recovered CH4 from Equation HH-4 of this section (metric tons CH4).
Rn = Quantity of recovered CH4 from Equation HH-4 of this section for the n[th] measurement location (metric tons CH4).

Harmonizing with changes to Equation HH-8 for multiple measurement locations and/or multiple destruction devices
                                      HH
98.343(c )(3)(ii)
(Eq. HH-8)
fRec = Fraction of hours the recovery system was operating (annual operating hours/8760 hours  per year).
fRec,n = Fraction of hours the recovery system associated with the n[th] measurement location was operating (annual operating hours/8760 hours  per year or annual operating hours / 8784 per year for a leap year).

Harmonizing with changes to Equation HH-8 for multiple measurement locations and/or multiple destruction devices
                                      HH
98.343(c )(3)(ii)
(Eq. HH-8)

OX = Oxidation fraction.  Use the default value of 0.1 (10%).
OX = Oxidation fraction. Use appropriate oxidation fraction default value from Table HH-4 of this subpart.

See proposal preamble (77 FR 19802)
                                      HH
98.343(c )(3)(ii)
(Eq. HH-8)
DE = Destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use DE = 1.
DEn = Destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99) for the n[th] measurement location. If the gas is transported off-site for destruction, use DE = 1. If the volumetric flow and CH4 concentration of the recovered gas is measured at a single location providing landfill gas to multiple destruction devices (including some gas destroyed on-site and some gas sent off-site for destruction), calculate DEn as the arithmetic average of the DE values determined for each destruction device associated with that measurement location.

Harmonizing with changes to Equation HH-8 for multiple measurement locations and/or multiple destruction devices
                                      HH
98.343(c)(3)(ii) (Eq. HH-8)
FDest, = Fraction of hours the destruction device was operating (device operating hours/8760 hours per year). If the gas is destroyed in a back-up flare (or similar device) or if the gas is transported off-site for destruction, use fDest= 1.
fDest,n = Fraction of hours the destruction device associated with the n[th] measurement location was operating during active gas flow calculated as the annual operating hours for the destruction device divided by the annual hours flow was sent to the destruction device as measured at the nth measurement location. If the gas is transported off-site for destruction, use fDest,n = 1. If the volumetric flow and CH4 concentration of the recovered gas is measured at a single location providing landfill gas to multiple destruction devices (including some gas destroyed on-site and some gas sent off-site for destruction), calculate fDest,n as the arithmetic average of the fDest values determined for each destruction device associated with that measurement location.

Yes
Harmonizing with changes to Equation HH-8 for multiple measurement locations and/or multiple destruction devices and clarifies equation term to more accurately reflect operating hours of gas collection system. See final preamble text.
                                      HH
98.344(e)
(e) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if applicable, gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
(e) For landfills electing to measure the fraction by volume of CH4 in landfill gas (F), follow the requirements in paragraphs (e)(1) and (e)(2) of this section.
(1) Use a gas composition monitor capable of measuring the concentration of CH4 on a dry basis that is properly operated, calibrated, and maintained according to the requirements specified in paragraph (b) of this section. You must either use a gas composition monitor that is also capable of measuring the O2 concentration correcting for excess (infiltration) air or you must operate, maintain, and calibrate a second monitor capable of measuring the O2 concentration on a dry basis according to the manufacturer's specifications.
(2) Use Equation HH-10 of this section to correct the measured CH4 concentration to 0% oxygen. If multiple CH4 concentration measurements are made during the reporting year, determine F separately for each measurement made during the reporting year, and use the results to determine the arithmetic average value of F for use in Equation HH - 1 of this part.

 F = (CCH4/100%)x[20.9c/(20.9-%O2)]     (Eq. HH-10)

Where:
F = Fraction by volume of CH4 in landfill gas (fraction, dry basis, corrected to 0 % oxygen).
CCH4 = Measured CH4 concentration in landfill gas (volume %, dry basis).
20.9c = Defined O2 correction basis, (volume percent, dry basis).
20.9 = O2 concentration in air (volume percent, dry basis).
%O2 = Measured O2 concentration in landfill gas (volume %, dry basis).

Harmonizing change to accommodate the correction to 0 percent oxygen for CH4 content of landfill gas
                                      HH
98.344(f)
(None)
(f) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if applicable, gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices and the technical basis for these estimates shall be recorded.

Harmonizing change.  Moves paragraph to accommodate new paragraph (e)
                                      HH
98.345(c)
(c) For missing daily waste disposal quantity data for disposal in  reporting years,  the substitute value shall be the average daily waste disposal quantity for that day of the week as measured on the week before and week after the missing daily data.
(c) For missing daily waste disposal quantity data for disposal in the reporting year,  the substitute value shall be the average daily waste disposal quantity for that day of the week as measured on the week before and week after the missing daily data.

See proposal preamble (77 FR 19802)
                                      HH
98.346(d)(1)
(1) Degradable organic carbon (DOC), methane correction factor (MCF), and fraction of DOC dissimilated (DOCF) values used in the calculations. If an MCF value other than the default of 1 is used, provide an indication of whether active aeration of the waste in the landfill was conducted during the reporting year, a description of the aeration system, including aeration blower capacity, the fraction of the landfill containing waste affected by the aeration, the total number of hours during the year the aeration blower was operated, and other factors used as a basis for the selected MCF value.
(1) Degradable organic carbon (DOC) and fraction of DOC dissimilated (DOCF) values used in the calculations.

See proposal preamble (77 FR 19802)
                                      HH
98.346(e)
(e) Fraction of CH4in landfill gas (F), and an indication of whether the fraction of CH4was determined based on measured values or the default value
(e) Fraction of CH4 in landfill gas (F), an indication of whether the fraction of CH4 was determined based on measured values or the default value, and the methane correction factor used in the calculations. If an MCF other than the default of 1 is used, provide an indication of whether active aeration of the waste in the landfill was conducted during the reporting year, a description of the aeration system, including aeration blower capacity, the fraction of the landfill containing waste affected by 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.

See proposal preamble (77 FR 19802)
                                      HH
98.346(h)
(h) For landfills without gas collection systems, the annual methane emissions (i.e., the methane generation, adjusted for oxidation, calculated using Equation HH - 5 of this subpart), reported in metric tons CH4,  and an indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in §98.6) are present at this landfill.
(h) For landfills without gas collection systems, the annual methane emissions (i.e., the methane generation, adjusted for oxidation, calculated using Equation HH - 5 of this subpart), reported in metric tons CH4, the oxidation fraction used in the calculation, and 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.

Harmonizes reporting requirements with calculation method.
                                      HH
98.346(i)(5)
(5) An indication of whether destruction occurs at the landfill facility or offsite. If destruction occurs at the landfill facility, also report an indication of whether a back-up destruction device is present at the landfill, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), and the destruction efficiency used (percent).

(5) An indication of whether destruction occurs at the landfill facility, off-site, or both. If destruction occurs at the landfill facility, also report for each measurement location the number of destruction devices associated with that measurement location and the annual operating hours and the destruction efficiency (percent) for each destruction device associated with that measurement location.

Yes
Clarification to provide landfills that use both off-site and on-site destruction a clear and accurate reporting option.
                                      HH
98.346(i)(6)
(6) Annual quantity of recovered CH4 (metric tons CH4) calculated using Equation HH - 4 of this subpart.
(6) Annual quantity of recovered CH4 (metric tons CH4) calculated using Equation HH - 4 of this subpart for each measurement location
Yes
Clarifies a reporting requirement. See final preamble text
                                      HH
98.346(i)(7)
(7) A description of the gas collection system (manufacturer, capacity, and number of wells), the surface area (square meters) and estimated waste depth (meters) for each area specified in Table HH - 3 to this subpart, the estimated gas collection system efficiency for landfills with this gas collection system, the annual operating hours of the gas collection system, and 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 the landfill.

(7) A description of the gas collection system (manufacturer, capacity, and number of wells), the surface area (square meters) and estimated waste depth (meters) for each area specified in Table HH - 3 to this subpart, the estimated gas collection system efficiency for landfills with this gas collection system, the annual operating hours of the gas collection system for each measurement location, and 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 the landfill.

Yes
Clarifies a reporting requirement. See final preamble text
                                      HH
98.346(i)(8)
(8) Methane generation corrected for oxidation calculated using Equation HH-5 of this subpart, reported in metric tons CH4.
(8) Methane generation corrected for oxidation calculated using Equation HH-5 of this subpart, reported in metric tons CH4, and the oxidation fraction used in the calculation

Harmonizes reporting requirements with calculation method.
                                      HH
98.346(i)(10)
(10) Methane generation corrected for oxidation calculated using Equation HH-7 of this subpart, reported in metric tons CH4.
(10) Methane generation corrected for oxidation calculated using Equation HH-7 of this subpart, reported in metric tons CH4, and the oxidation fraction used in the calculation

Harmonizes reporting requirements with calculation method.
                                      HH
98.346(i)(11)
(11) Methane generation corrected for oxidation calculated using Equation HH-6 of this subpart, reported in metric tons CH4.
(11) Methane emissions calculated using Equation HH-6 of this subpart, reported in metric tons CH4, and the oxidation fraction used in the calculation

Harmonizes reporting requirements with calculation method.
                                      HH
98.346(i)(12)
(12) Methane generation corrected for oxidation calculated using Equation HH-8 of this subpart, reported in metric tons CH4.
(12) Methane emissions calculated using Equation HH-8 of this subpart, reported in metric tons CH4, and the oxidation fraction used in the calculation

Harmonizes reporting requirements with calculation method.
                                      HH
98.348
(None)
Landfill capacity  means the maximum amount of solid waste a landfill can accept. For the purposes of this subpart, for landfills that have a permit, the landfill capacity can be determined in terms of volume or mass in the most recent permit issued by the state, local, or Tribal agency responsible for regulating the landfill, plus any in-place waste not accounted for in the most recent permit. If the owner or operator chooses to convert from volume to mass to determine its capacity, the calculation must include a site-specific density.

Add definition to clarify meaning of term as used in the rule.
                                      HH
98.348
(None)
Leachate recirculation  means the practice of taking the leachate collected from the landfill and reapplying it to the landfill by any of one of a variety of methods, including pre-wetting of the waste, direct discharge into the working face, spraying, infiltration ponds, vertical injection wells, horizontal gravity distribution systems, and pressure distribution systems.

Add definition to clarify meaning of term as used in the rule.
                                      HH
Table HH-1
Table HH-1
See Appendix A for changes to Table HH-1

                                      HH
Table HH-2
Table HH-2
See Appendix A for changes to Table HH-2

Effect changes that were intended to be made in the October 28, 2010 (75 FR 66474) amendments and revise the last line of this table to read "2009 and all later years".
                                      HH
Table HH-4
None
See Appendix A for Table HH-4
Yes
See final preamble text for explanation
                                      II
98.353(d)(2) - Eq. II-6
fDest_1 = Fraction of hours the primary destruction device was operating (device operating hours/hours in the year). If the biogas is transported off-site for destruction, use fDest = 1.
fDest_1 = Fraction of hours the primary destruction device was operating calculated as the annual hours when the destruction device was operating divided by the annual operating hours of the biogas recovery system. If the biogas is transported off-site for destruction, use fDest = 1.

Clarifies an equation term to more accurately reflect operating hours of biogas recovery system.
                                      II
98.353(d)(2) - Eq. II-6
fDest_2 = Fraction of hours the back-up destruction device was operating (device operating hours/hours in the year).
fDest_2 = Fraction of hours the back-up destruction device was operating calculated as the annual hours when the destruction device was operating divided by the annual operating hours of the biogas recovery system.

Clarifies equation term to more accurately reflect operating hours of biogas recovery system.
                                      LL
98.386(a)(1)
(1) For each product listed in Table MM-1 of subpart MM of this part that enters the coal-to-liquid facility to be further processed or otherwise used on site, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.
(1) [Reserved.]

See proposal preamble (77 FR 19802)
                                      LL
98.386(a)(4)
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(1) of this section.
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(2) of this section.

Harmonizing change with 40 CFR 98.386(a)(1).
                                      LL
98.386(a)(5)
(5) For each product (leaving the coal-to-liquid facility) listed in Table MM-1 of subpart MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. Those products that enter the facility, but are not reported in (a)(1), shall not be reported under this paragraph.
(5) [Reserved.]

See proposal preamble (77 FR 19802)
                                      LL
98.386(a)(8)
(8) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(5) of this section.
(8) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(6) of this section.

Harmonizing change with 40 CFR 98.386(a)(5).
                                      LL
98.386(a)(9)(v)
(v) The calculated CO2 emissions factor.
(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product.

Clarifies units of reporting requirement
                                      LL
98.386(a)(11)(v)
(v) The calculated CO2 emissions factor.
(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product.

Clarifies units of reporting requirement
                                      LL
98.386(a)(12)
(12) For every non-solid product reported in paragraph (a)(6) of this section for which Calculation Methodology 2 of subpart MM of this part was used to determine an emissions factor, report:
(12) For every non-solid product reported in paragraph (a)(6) of this section for which Calculation Method 2 of subpart MM of this part was used to determine an emissions factor, report:

Harmonizing change with 40 CFR 98.393(f)(2).
                                      LL
98.386(a)(13)
(13)For each specific type of biomass that enters the coal-to-liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used.
(13) [Reserved.]

See proposal preamble (77 FR 19802)
                                      LL
98.386(a)(14)
(14) For each specific type of biomass that enters the coal-to-liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the total annual quantity in metric tons or barrels.
(14) For each specific type of biomass that enters the coal-to-liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels.

                                      LL
98.386(a)(15)
(15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(3) of this section.
(15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(14 ) of this section.

Harmonizing change with 40 CFR 98.386(a)(13) and corrects reference
                                      LL
98.386(a)(18)
(18) Annual CO2 emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co-processed with fossil fuel-based feedstocks reported in paragraph (a)(3) of this section, calculated according to §98.393(c).
(18) Annual CO2 emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co-processed with fossil fuel-based feedstocks reported in paragraph (a)(14) of this section, calculated according to §98.393(c).

Harmonizing change with 40 CFR 98.386(a)(13) and corrects reference
                                      LL
98.386(b)(1)
(1) For each product listed in Table MM-1 of subpart MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.
(1) [Reserved.]

See proposal preamble (77 FR 19802)
                                      LL
98.386(b)(4)
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)(1) of this section.
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)(2) of this section.

Harmonizing change with 40 CFR 98.386 (b)(1)
                                      LL
98.386(b)(5)(v)
(v) The calculated CO2 emissions factor in metric tons.
(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product.

Clarifies units of reporting requirement
                                      LL
98.386( c)(1)
(1) For each product listed in Table MM-1 of subpart MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.
(1) [Reserved.]

See proposal preamble (77 FR 19802)
                                      LL
98.386( c)(4)
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)(1) of this section
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)(2) of this section

Harmonizing change with 40 CFR 98.386 (c)(1)
                                      LL
98.386( c)(5)(v)
(v) The calculated CO2 emissions factor in metric tons.
(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product.

Clarifies units of reporting requirement
                                      LL
98.386(d)(2)
(2) For a product that enters the facility to be further refined or otherwise used on site that is a blended feedstock, producers must meet the reporting requirements of paragraphs (a)(1) and (a)(2) of this section by reflecting the individual components of the blended feedstock.
(2) For a product that enters the facility to be further refined or otherwise used on site that is a blended feedstock, producers must meet the reporting requirements of paragraph (a)(2) of this section by reflecting the individual components of the blended feedstock.

Harmonizing change with 40 CFR 98.386(a)(1).
                                      LL
98.386(d)(3)
(3) For a product that is produced, imported, or exported that is a blended product, producers, importers, and exporters must meet the reporting requirements of paragraphs (a)(5), (a)(6), (b)(1), (b)(2), (c)(1), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product.
(3) For a product that is produced, imported, or exported that is a blended product, producers, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product.

Harmonizing change with 40 CFR 98.386(a)(1), (b)(1), and (c )(1)
                                      MM
98.393(a)(1)
Producti  = Annual volume of product "i" produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate, and excludes products that entered the refinery but are not reported under 98.396(a)(1).  For natural gas liquids, volumes shall reflect the individual components of the product as listed in Table MM-1 to subpart MM.
Producti  = Annual volume of product "i" produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate, and excludes products that entered the refinery but are not reported under 98.396(a)(2).  For natural gas liquids, volumes shall reflect the individual components of the product as listed in Table MM-1 to subpart MM.

Updated reference to harmonize with changes to 98.396(a)(1)
                                      MM
98.393(a)(2)
Producti  = Annual mass of product "i" produced, imported, or exported by the reporting party (metric tons). For refiners, this mass only includes products ex refinery gate.
Producti  = Annual mass of product "i" produced, imported, or exported by the reporting party (metric tons). For refiners, this mass only includes products ex refinery gate, and excludes products that entered the refinery but are not reported under §98.396(a)(2).

See proposal preamble (77 FR 19802)
                                      MM
98.393(h)(1)
(1) A reporter using Calculation Methodology 1 to determine the emission factor of a petroleum product shall calculate the CO2 emissions associated with that product using Equation MM - 8 of this section in place of Equation MM - 1 of this section.
(1) A reporter using Calculation Method 1 to determine the emission factor of a petroleum product shall calculate the CO2 emissions associated with that product using Equation MM - 8 of this section in place of Equation MM - 1 of this section.

Harmonizing change with 98.393(f)(1).
                                      MM
98.393(h)(2)
A refinery using Calculation Methodology 1 of this subpart to determine the emission factor of a non-crude petroleum feedstock shall calculate the CO2 emissions associated with that feedstock using Equation MM - 9 of this section in place of Equation MM - 2 of this section.
(2) A refinery using Calculation Method 1 of this subpart to determine the emission factor of a non-crude petroleum feedstock shall calculate the CO2 emissions associated with that feedstock using Equation MM - 9 of this section in place of Equation MM - 2 of this section.

Harmonizing change with 98.393(f)(1).
                                      MM
98.394(a)(1)
(1) The quantity of petroleum products, natural gas liquids, and biomass, as well as the quantity of crude oil measured on site at a refinery, shall be determined as follows:
(1) The quantity of petroleum products, natural gas liquids, and biomass, shall be determined as follows:

See proposal preamble (77 FR 19802)
                                      MM
98.394(a)(3)
(3) The quantity of crude oil not measured on site at a refinery shall be determined according to one of the following methods. You may use an appropriate standard method published by a consensus-based standards organization or you may use an industry standard practice.
(3) The annual quantity of crude oil received shall be determined according to one of the following methods. You may use an appropriate standard method published by a consensus-based standards organization or you may use an industry standard practice.

See proposal preamble (77 FR 19802)
                                      MM
98.394(b)(3)
(None)
(3) For units and processes that operate continuously with infrequent outages, it may not be possible to complete the calibration of a flow meter or other measurement device without disrupting normal process operation. In such cases, the owner or operator may postpone the calibration until the next scheduled maintenance outage. The best available information from company records may be used in the interim. Such postponements shall be documented in the monitoring plan that is required under §98.3(g)(5).

See proposal preamble (77 FR 19802)
                                      MM
98.394(c)
(c) Procedures for Calculation Methodology 2 of this subpart.
(c) Procedures for Calculation Method 2 of this subpart.

Harmonizing change with 98.393(f)(2).
                                      MM
98.394(d)
(d) Measurement of API gravity and sulfur content of crude oil.
None

See proposal preamble (77 FR 19802)
                                      MM
98.395(a)
(a) Determination of quantity. Whenever the quality assurance procedures in §98.394(a) cannot be followed to measure the quantity of one or more petroleum products, natural gas liquids, types of biomass, feedstocks, or crude oil batches during any period (e.g., if a meter malfunctions), the following missing data procedures shall be used:
(a) Determination of quantity. Whenever the quality assurance procedures in §98.394(a) cannot be followed to measure the quantity of one or more petroleum products, natural gas liquids, types of biomass, feedstocks, or crude oil during any period (e.g., if a meter malfunctions), the following missing data procedures shall be used:

See proposal preamble (77 FR 19802)
                                      MM
98.395(b)
(b) Determination of emission factor. Whenever any of the procedures in §98.394(c) cannot be followed to develop an emission factor for any reason, Calculation Methodology 1 of this subpart must be used in place of Calculation Methodology 2 of this subpart for the entire reporting year.
(b) Determination of emission factor. Whenever any of the procedures in §98.394(c) cannot be followed to develop an emission factor for any reason, Calculation Method 1 of this subpart must be used in place of Calculation Method 2 of this subpart for the entire reporting year.

Clarifies method
                                      MM
98.395(c )
(c) Determination of API gravity and sulfur content of crude oil. For missing data on sulfur content or API gravity, the substitute data value shall be the arithmetic average of the quality-assured values of API gravity or sulfur content in the batch preceding and the batch immediately following the missing data incident. If no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured values for API gravity and sulfur content obtained from the batch after the missing data period.
None

See proposal preamble (77 FR 19802)
                                      MM
98.396(a)(1)
(1) For each petroleum product or natural gas liquid listed in table MM - 1 of this subpart that enters the refinery to be further refined or otherwise used on site, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.
(1) [Reserved]

See proposal preamble (77 FR 19802)
                                      MM
98.396(a)(4)
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(1) of this section.
(4) [Reserved]
Yes
See final preamble text for explanation
                                      MM
98.396(a)(5)
(5) For each petroleum product and natural gas liquid (ex refinery gate) listed in Table MM - 1 of this subpart, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product. Petroleum products and natural gas liquids that enter the refinery, but are not reported in (a)(1), shall not be reported under this paragraph.
(5) [Reserved]

See proposal preamble (77 FR 19802)
                                      MM
98.396(a)(8)
(8) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(5) of this section.
(8) [Reserved]
Yes
See final preamble text for explanation
                                      MM
98.396(a)(9)
(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:

Corrects terminology
                                      MM
98.396(a)(9)(iii)
(iii) The carbon share test results in percentmass.
(iii) The carbon share test results in percent mass.

Corrects typographical error
                                      MM
98.396(a)(9)(v)
(v) The calculated CO2 emissions factor in metric tons.
(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product.

Clarifies units of reporting requirement
                                      MM
98.396(a)(10)
(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:
(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:

Clarifies method
                                      MM
98.396(a)(11)
(11) For every petroleum product and natural gas liquid reported in paragraph (a)(6) of this section for which Calculation Methodology2 of this subpart was used to determine an emissions factor, report:
(11) For every petroleum product and natural gas liquid reported in paragraph (a)(6) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:

Clarifies method
                                      MM
98.396(11)(iii)
(iii) The carbon share test results in percentmass.
(iii) The carbon share test results in percent mass.

Corrects typo
                                      MM
98.396(a)(13)
(13) For each specific type of biomass that enters the refinery to be co-processed with petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used.
(13) [Reserved]

See proposal preamble (77 FR 19802)
                                      MM
98.396(a)(15)
(15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(13) of this section.
(15) [Reserved]
Yes
See final preamble text for explanation
                                      MM
98.396(a)(18)
(18) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co-processed with petroleum feedstocks reported in paragraph (a)(13) of this section, calculated according to §98.393(c).
(18) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co-processed with petroleum feedstocks reported in paragraph (a)(14) of this section, calculated according to §98.393(c).

Harmonizing change with 40 CFR 98.396(a)(13)
                                      MM
98.396(a)(20)
(20) All of the following information for all crude oil feedstocks used at the refinery:
(i) Batch volume in barrels.
(ii) Weighted average API gravity representing the batch at the point of entry at the refinery.
(iii) Weighted average sulfur content representing the batch at the point of entry at the refinery.
(iv) Country of origin, of the batch, if known and data in paragraphs (a)(20)(v) and (a)(20)(vi) of this section are unknown.
(v) EIA crude stream code and crude stream name of the batch, if known.
(vi) Generic name for the crude stream and the appropriate EIA two-letter country or state and production area code of the batch, if known and no appropriate EIA crude stream code exists.
(20) For all crude oil that enters the refinery, report the annual quantity in barrels.

See proposal preamble (77 FR 19802)
                                      MM
98.396(a)(21)
(21) The quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year.
(21) The quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. Report only quantities of bulk NGLs not reported in (a)(2) of this section.

See proposal preamble (77 FR 19802)
                                      MM
98.396(a)(22)
(22) Volume of crude oil in barrels that you injected into a crude oil supply or reservoir. A volume of crude oil that entered the refinery, but was not reported in paragraphs (a)(2) or (a)(20), shall not be reported under this paragraph.
(22) Volume of crude oil in barrels that you injected into a crude oil supply or reservoir.

See proposal preamble (77 FR 19802)
                                      MM
98.396(a)(23)
(23) Special provisions for 2010. For reporting year 2010 only, a refiner that knows the information under a specific tier of the batch definition in 40 CFR 98.398, but does not have the necessary data collection and management in place to readily report this information, can use the next most appropriate tier of the batch definition for reporting batch information under paragraph 98.396(a)(20).
None

Special provisions for 2010 are no longer necessary.
                                      MM
98.396(b)(1)
(1) For each petroleum product and natural gas liquid listed in Table MM - 1 of this subpart, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.
(1) [Reserved]

See proposal preamble (77 FR 19802)
                                      MM
98.396(b)(2)
(2) For each petroleum product and natural gas liquid listed in Table MM - 1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product as listed in Table MM - 1 of this subpart.
(2) For each petroleum product and natural gas liquid listed in Table MM - 1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

Clarifies reporting requirements.  Reporting is not limited to those components listed in Table MM-1.
                                      MM
98.396(b)(4)
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)(1) of this section.
(4) [Reserved]
Yes
See final preamble text for explanation
                                      MM
98.396(b)(5)
(5) For each product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report:
(5) For each product reported in paragraph (b)(2) of this section for which Calculation Method 2 of this subpart used was used to determine an emissions factor, report:

Clarifies method
                                      MM
98.396(b)(6)
(6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:
(6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:

Clarifies method
                                      MM
98.396( c)(1)
(1) For each petroleum product and natural gas liquid listed in Table MM - 1 of this subpart, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.
(1)[Reserved]

See proposal preamble (77 FR 19802)
                                      MM
98.396( c)(4)
(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)(1) of this section.
(4) [Reserved]
Yes
See final preamble text for explanation
                                      MM
98.396(c)(5)
(5) For each product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:
(5) For each product reported in paragraph (c)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:

Clarifies method
                                      MM
98.396(c)(6)
(6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report:
(6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Method 2 of this subpart used was used to determine an emissions factor, report:

Clarifies method
                                      MM
98.396(d)(2)
(2) For a product that enters the refinery to be further refined or otherwise used on site that is a blended non-crude feedstock, refiners must meet the reporting requirements of paragraphs (a)(1) and (a)(2) of this section by reflecting the individual components of the blended non-crude feedstock.
(2) For a product that enters the refinery to be further refined or otherwise used on site that is a blended non-crude feedstock, refiners must meet the reporting requirements of paragraph (a)(2) of this section by reflecting the individual components of the blended non-crude feedstock.

Harmonizing change with 40 CFR 98.396 (a)(1)
                                      MM
98.396(d)(3)
(3) For a product that is produced, imported, or exported that is a blended product, refiners, importers, and exporters must meet the reporting requirements of paragraphs (a)(5), (a)(6), (b)(1), (b)(2), (c)(1), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product.
(3) For a product that is produced, imported, or exported that is a blended product, refiners, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product.

Harmonizing change with 40 CFR 98.396 (a)(1), (b)(1), and (c )(1)
                                      MM
98.397(b)
(b) Reporters shall maintain records to support quantities that are reported under this subpart, including records documenting any estimations of missing data and the number of calendar days in the reporting year for which substitute data procedures were followed. For all reported quantities of petroleum products, natural gas liquids, and biomass, as well as crude oil quantities measured on site at a refinery, reporters shall maintain metering, gauging, and other records normally maintained in the course of business to document product and feedstock flows including the date of initial calibration and the frequency of recalibration for the measurement equipment used.
(b) Reporters shall maintain records to support quantities that are reported under this subpart, including records documenting any estimations of missing data and the number of calendar days in the reporting year for which substitute data procedures were followed. For all reported quantities of petroleum products, natural gas liquids, and biomass, reporters shall maintain metering, gauging, and other records normally maintained in the course of business to document product and feedstock flows including the date of initial calibration and the frequency of recalibration for the measurement equipment used.

Harmonizing change with 40 CFR 98.396(a)(20).
                                      MM
98.397(d)
(d) Reporters shall maintain laboratory reports, calculations and worksheets used in the measurement of density and carbon share for any petroleum product or natural gas liquid for which CO2 emissions were calculated using Calculation Methodology 2.
(d) Reporters shall maintain laboratory reports, calculations and worksheets used in the measurement of density and carbon share for any petroleum product or natural gas liquid for which CO2 emissions were calculated using Calculation Method 2.

Clarifies method
                                      MM
98.398
(None)
Bulk NGLs for purposes of reporting under this subpart means mixtures of NGLs that are sold or delivered as undifferentiated product.

See proposal preamble (77 FR 19802)
                                      MM
98.398
(None)
Natural Gas Liquids (NGLs) for the purposes of reporting under this subpart means hydrocarbons that are separated from natural gas as liquids through the process of absorption, condensation, adsorption, or other methods, and are sold or delivered as differentiated product. Generally, such liquids consist of ethane, propane, butanes, or pentanes plus.

See proposal preamble (77 FR 19802)
                                      MM
98.398
Batch means either a volume of crude oil that enters a refinery or the components of such volume (e.g., the volumes of different crude streams that are blended together and then delivered to a refinery). The batch volume is the first appropriate tier in the following list:
(1) Up to an annual volume of a type of crude oil identified by an EIA crude stream code, if the EIA crude stream code is known.
(2) Up to an annual volume of a type of crude oil identified by a generic name for the crude stream and an appropriate EIA two-letter country or state and production area code, if the generic name and EIA two-letter code are known but no appropriate EIA crude stream code exists.
(3) Up to a calendar month of crude oil volume from a single known foreign country of origin if the crude stream name is unknown.
(4) Up to a calendar month of crude oil volume from the United States if the crude stream name and production area are unknown.
(5) Up to a calendar month of crude oil volume if the country of origin is unknown.
(None)

See proposal preamble (77 FR 19802)
                                      MM
Table MM-1
Table MM-1
See Appendix A for changes to Table MM-1

See proposal preamble (77 FR 19802)
                                      NN
98.400(a)
(a) Natural gas liquids fractionators are installations that fractionate natural gas liquids (NGLs) into their consitutent liquid products (ethane, propane, normal butane, isobutane or pentanes plus) for supply to downstream facilities.
(a) Natural gas liquids fractionators are installations that fractionate natural gas liquids (NGLs) into their constituent liquid products or mixtures of products (ethane, propane, normal butane, isobutane or pentanes plus) for supply to downstream facilities.

Clarifies rule text.
                                      NN
98.400(b)
(b) Local Distribution Companies (LDCs) are companies that own or operate distribution pipelines, not interstate pipelines or intrastate pipelines, that physically deliver natural gas to end users and that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution systems.
(b) Local Distribution Companies (LDCs) are companies that own or operate distribution pipelines, not interstate pipelines or intrastate pipelines, that physically deliver natural gas to end users and that are within a single state that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution systems. LDCs do not include pipelines (both interstate and intrastate) delivering natural gas directly to major industrial users and farm taps upstream of the local distribution company inlet.

See proposal preamble (77 FR 19802)
                                      NN
98.403(a)(2)
Fuelh = Total annual volume of product "h" supplied (bbl or Mscf per year)
Fuelh = Total annual volume of product "h" supplied (volume per year, in Mscf for natural gas and bbl for NGLs).

Clarifies equation term.
                                      NN
98.403(b) (1)
(1) For natural gas that is received for redelivery to downstream gas transmission pipelines and other local distribution companies, use eEquation NN - 3 of this section and the default values for the CO2 emission factors found in Table NN - 2 of this subpart.***
(1) For natural gas that is received for redelivery to downstream gas transmission pipelines and other local distribution companies, use Equation NN - 3 of this section and the default values for the CO2 emission factors found in Table NN - 2 of this subpart.***.

Corrects typographical error
                                      NN
98.403(b)(2)(i)
(2)(i) For natural gas delivered to each meter registering a supply equal to or greater than 460,000 Mscf per year, use Equation NN - 4 of this section and the default values for the CO2 emission factors found in Table NN - 2 of this subpart.
(2)(i) For natural gas delivered to large end-users, use Equation NN - 4 of this section and the default values for the CO2 emission factors found in Table NN - 2 of this subpart. A large end-user means any end-user facility receiving greater than or equal to 460,000 Mscf of natural gas per year. If the LDC does not know the total quantity of gas delivered to the end-user facility based on readily available information in the LDCs possession, then large end-user means any single meter at an end-user facility to which the LDC delivers equal to or greater than 460,000 Mscf per year.
Yes
See final preamble text for explanation
                                      NN
98.403(b)(2)(ii)
CO2k =  Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas received by end-users that receive a supply equal to or greater than 460,000 Mscf per year (metric tons).
CO2k =  Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas delivered to each large end-user k, as defined in paragraph (b)(2)(i) of this section (metric tons).
Yes
Clarifies rule text. Final rule is revised to replace the term "end-user" with "large end-user".
                                      NN
98.403(b)(2)(ii)
Fuel = Total annual volume of natural gas supplied (Mscf per year).
Fuel = Total annual volume of natural gas supplied to each large end-user k, as defined in paragraph (b)(2)(i) of this section (Mscf per year).
Yes
Clarifies the definition of the equation term "Fuel" in Equation NN-4" . The input for the total annual volume of natural gas must be the total annual volume of natural gas supplied to the end-user, if known. Final rule is revised to replace the term "end-user" with "large end-user".
                                      NN
98.403(b)(3)
(3) For natural gas received by the LDC at the city gate that is injected into on-system storage, and/or liquefied and stored, use Equation NN - 5 of this section and the default value for the CO2 emission factors found in Table NN - 2 of this subpart. Alternatively, a reporter-specific CO2 emission factor may be used, provided it is developed using methods outlined in §98.404.
CO2l = [Fuel1-Fuel2]*EF (Eq. NN-5)
Where:
CO2l = Annual CO2 mass emissions that would result from the combustion or oxidation of the net natural gas that is liquefied and/or stored and not used for deliveries by the LDC within the reported year (metric tons).
Fuel1 = Total annual volume of natural gas received by the LDC at the city gate and stored on-system or liquefied and stored in the reporting year (Mscf per year).
Fuel2 = Total annual volume of natural gas that is used for deliveries in the reporting year that was not otherwise accounted for in Equation NN - 1 or NN - 2 of this section (Mscf per year). This primarily includes natural gas previously stored on-system or liquefied and stored that is removed from storage and used for deliveries to customers or other LDCs by the LDC within the reporting year. This also includes natural gas that bypassed the city gate and was delivered directly to LDC systems from producers or natural gas processing plants from local production.
EF = Fuel-specific CO2 emission factor (MT CO2/Mscf).
(3) For the net change in natural gas stored on system by the LDC during the reporting year, use Equation NN-5a of this section. For natural gas that is received by means other than through the city gate, and is not otherwise accounted for by Equation NN-1 or NN-2 of this section, use Equation NN-5b of this section.
(i) For natural gas received by the LDC that is injected into on-system storage, and/or liquefied and stored, and for gas removed from storage and used for deliveries, use Equation NN - 5a of this section and the default value for the CO2 emission factors found in Table NN - 2 of this subpart. Alternatively, a reporter-specific CO2 emission factor may be used, provided it is developed using methods outlined in §98.404.
CO2l = [Fuel1-Fuel2]*EF (Eq. NN-5a)
Where:
CO2l = Annual CO2 mass emissions that would result from the combustion or oxidation of the net change in natural gas stored on system by the LDC within the reporting year (metric tons).
Fuel1 = Total annual volume of natural gas added to storage on-system or liquefied and stored in the reporting year (Mscf per year).
Fuel2 = Total annual volume of natural gas that is removed from storage or vaporized and removed from storage and used for deliveries to customers or other LDCs by the LDC within the reporting year (Mscf per year).
EF = Annual average CO2 emission factor for natural gas placed into/removed from storage (MT CO2/Mscf).

Harmonize with changes to equations - see proposal preamble (77 FR 19802)for a complete explanation of the changes.
                                      NN
98.403(b)(3)(ii)
(None)
(ii) For natural gas received by the LDC that bypassed the city gate, use Equation NN-5b of this section. This includes natural gas received directly by LDC systems from producers or natural gas processing plants from local production, received as a liquid and vaporized for delivery, or received from any other source that bypassed the city gate. Use the default value for the CO2 emission factors found in Table NN - 2 of this subpart. Alternatively, a reporter-specific CO2 emission factor may be used, provided it is developed using methods outlined in §98.404.
CO2n = Fuelz * EFz  (Eq. NN-5b)
 Where:
CO2n = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas received that bypassed the city gate and is not otherwise accounted for by Equation NN-1 or NN-2 of this section (metric tons).
Fuelz = Total annual volume of natural gas received that was not otherwise accounted for by Equation NN-1 or NN-2 of this section (natural gas from producers and natural gas processing plants from local production, or natural gas that was received as a liquid, vaporized and delivered, and any other source that bypassed the city gate) (Mscf per year).
EFz = Fuel-specific CO2 emission factor (MT CO2/Mscf).

Harmonize with changes to equations. See proposal preamble (77 FR 19802) for a complete description of the changes.
                                      NN
98.403(b)(4)
(4) Calculate the total CO2 emissions that would result from the complete combustion or oxidation of the annual supply of natural gas to end-users using Equation NN - 6 of this section.
CO2 = Sum(CO2i)-Sum(CO2j)-Sum(CO2k)-Sum(CO2l)
Where:
CO2 = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas delivered to LDC customers not covered in paragraph (b)(2) of this section (metric tons).
CO2i =Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas delivered to transmission pipelines or other LDCs as calculated in paragraph (b)(1) of this section (metric tons).
CO2j = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas delivered to transmission pipelines or other LDCs as calculated in paragraph (b)(1) of this section (metric tons).
CO2k = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas received by end-users that receive a supply equal to or greater than 460,000 Mscf per year as calculated in paragraph (b)(2) of this section (metric tons).
CO2l = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas received by the LDC and liquefied and/or stored but not used for deliveries within the reported year as calculated in paragraph (b)(3) of this section (metric tons).

(4) Calculate the total CO2 emissions that would result from the complete combustion or oxidation of the annual supply of natural gas to end-users that receive a supply less than 460,000 Mscf per year using Equation NN - 6 of this section.
CO2 = CO2i+CO2n-CO2j-∑CO2k-CO2l (Eq. NN-6)
Where
CO2 = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas delivered to LDC end-users not covered in paragraph (b)(2) of this section (metric tons).
CO2i = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas received at the city gate as calculated in paragraph (a)(1) or (a)(2) of this section (metric tons).
CO2j = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas delivered to transmission pipelines or other LDCs as calculated in paragraph (b)(1) of this section (metric tons).
CO2k = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas delivered to each large end-user as calculated in paragraph (b)(2) of this section (metric tons).
CO2l = Annual CO2 mass emissions that would result from the combustion or oxidation of the net change in natural gas stored by the LDC within the reported year as calculated in paragraph (b)(3)(i) of this section (metric tons).
CO2n = Annual CO2 mass emissions that would result from the combustion or oxidation of natural gas that was received by the LDC directly from sources  bypassing the city gate, and is not otherwise accounted for in Equation NN-1 or NN-2 of this section, as calculated in paragraph (b)(3)(ii) of this section (metric tons).
Yes
Harmonize with changes to equations - see proposal preamble (77 FR 19802)for a complete explanation. Final rule revises text to add term "large end user".
                                      NN
98.403( c)(2)
(2) Calculate the total CO2 equivalent emissions that would result from the combustion or oxidation of fractionated NGLs supplied less the quantity received by other fractionators using Equation NN-8 of this section.
(2) Calculate the total CO2 equivalent emissions that would result from the combustion or oxidation of fractionated NGLs supplied less the quantity received from other fractionators using Equation NN-8 of this section.

Clarifies rule language
                                      NN
98.403( c)(2)
CO2 = Annual CO2 mass emissions that would result from the combustion or oxidation of fractionated NGLs delivered to customers or on behalf of customers (metric tons).
CO2 = Annual CO2 mass emissions that would result from the combustion or oxidation of fractionated NGLs delivered to customers or on behalf of customers less the quantity received from other fractionators (metric tons).

Clarifies calculation result
                                      NN
98.404(a)(5)
(5) For an LDC using Equation NN - 1 or NN - 2 of this subpart, the point(s) of measurement for the natural gas volume supplied shall be the LDC city gate meter(s).

(5) For an LDC using Equation NN - 1 or NN - 2 of this subpart, the point(s) of measurement for the natural gas volume received shall be the LDC city gate meter(s).

Clarifies rule language
                                      NN
98.404(a)(7)