Page 1 of 40
**Subpart MM —**  **Suppliers of Petroleum Products**

This source category consists of petroleum refineries and importers and exporters of petroleum products and natural gas liquids as listed in Table MM

– 1 of this subpart. § 98.390 Definition of the source category.

(a) A petroleum refinery for the purpose of this subpart is any facility engaged in producing petroleum products through the distillation of crude oil. (b) A refiner is the owner or operator of a petroleum refinery. (c) Importer has the same meaning given in §98.6 and includes any entity that imports petroleum products or natural gas liquids as listed in Table MM

– 1 of this subpart. Any blender or refiner of refined or semi

- refined pet roleum products shall be considered an importer if it otherwise satisfies the aforementioned definition. (d) Exporter has the same meaning given in §98.6 and includes any entity that exports petroleum products or natural gas liquids as listed in Table MM

– 1 of this subpart. Any blender or refiner of refined or semi

- refined petroleum products shall be considered an exporter if it otherwise satisfies the aforementioned definition. § 98.391 Reporting threshold.Page 2 of 40 Any supplier of petroleum products who meets the

r equirements of §98.2(a)(4) must report GHG emissions.

Suppliers of petroleum products must report the CO § 98.392 GHGs To report.

2 emissions that would result from the complete combustion or oxidation of each petroleum product and natural gas liquid produc ed, used as feedstock, imported, or exported during the calendar year. Additionally, refiners must report CO 2 emissions that would result from the complete combustion or oxidation of any biomass co

- processed with petroleum feedstocks.

(a) Calculation for individual products produced, imported, or exported. § 98.393 Calculating GHG emissions.

(1) Except as provided in paragraphs (h) and (i) of this section, any refiner, importer, or exporter shall calculate CO 2 emissions from each individual petroleum produc t and natural gas liquid using Equation MM

– 1 of this section.

Where:

CO 2 i = Annual CO 2

Product emissions that would result from the complete combustion or oxidation of each petroleum product or natural gas liquid “i” (metric tons).

i = Annual volume of p roduct “i” produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate, andPage 3 of 40 excludes products that entered the refinery but are not reported under §98.396(a)( 1 2 ). For natural gas liqui ds, volumes shall reflect the individual components of the product as listed in Table MM

– 1 to subpart MM. EF i = Product

- specific CO 2 emission factor (metric tons CO 2 (2) In the event that an individual petroleum product is produced as a solid rather than liquid any refiner, importer, or exporter shall calculate CO per barrel).

2

Where: emissions using Equation MM

– 1 of this section.

CO 2 i = Annual CO 2

Product emissions that would result from the complete combustion or oxidation of each petroleum product “i” (metric tons).

i

EF = 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 )
. i = Product

- specific CO 2 emission factor (metric tons CO 2 (b) Calculation for individual products that enter a refinery as a non

- crude feedstock. per metric ton of product).

(1) Except as provided in paragraphs (h) and (i) of this section, any refiner shall calculate CO 2 emissions from each non

crude feedstock using Equation MM

– 2 of this section.

Where:Page 4 of 40

CO 2 j = Annual CO 2

Feedstock emissions that would result from the complete combustion or oxidation of each non

crude feedstock “j” (metric tons).
j

EF = Annual volume of a petroleum product or natural gas liquid “j” that enters the refinery to be further refined or otherwise used on site (barrels). For natural gas liquids, volumes shall reflect the individual components of the product as liste d in table MM

– 1 of this subpart.
j = Feedstock

- specific CO 2 emission factor (metric tons CO 2 (2) In the event that a non

- crude feedstock enters a refinery as a solid rather than liquid, the refiner shall calculate CO per barrel).

2 Where: emissions using Equatio n MM

– 2 of this section.

CO 2 j = Annual CO 2

Feedstock emissions that would result from the complete combustion or oxidation of each non

crude feedstock “j” (metric tons).
j

EF = Annual mass of a petroleum product “j” that enters the refinery to be further refined or otherwise used on site (metric tons).
j = Feedstock

- specific CO 2 emission factor (metric tons CO 2 (c) Calculation for biomass co

- processed with petroleum feedstocks. per metric ton of feedstock).

(1) Refiners shall calculate CO 2 emissions fro m each type of biomass that enters a refinery and is co

- processed with petroleum feedstocks using Equation MM

– 3 of this section.

Where:Page 5 of 40

CO 2 m = Annual CO 2

Biomass emissions that would result from the complete combustion or oxidation of each type of biomass “m” ( metric tons).

m

EF = Annual volume of a specific type of biomass that enters the refinery and is co

- processed with petroleum feedstocks to produce a petroleum product reported under paragraph (a) of this section (barrels).

m = Biomass

- specific CO 2 emission factor (metric tons CO 2 (2) In the event that biomass enters a refinery as a solid rather than liquid and is co

- processed with petroleum feedstocks, the refiner shall calculate CO per barrel).

2

Where: emissions from each type of biomass using Equation MM

– 3 of this section.

CO 2 m = Annual CO 2

Biomass emissions that would result from the complete combustion or oxidation of each type of biomass “m” (metric tons).

m

EF = Total annual mass of a specific type of biomass that enters the refinery to be co

proce ssed with petroleum feedstocks to produce a petroleum product reported under paragraph (a) of this section (metric tons).

m = Biomass

- specific CO 2 emission factor (metric tons CO 2 (d) per metric ton of biomass). Summary calculation for refinery products
. Refiners shall calculate annual CO 2 emissions from all products using Equation MM

– 4 of this section.

Where:

CO 2 r = Annual CO 2 emissions that would result from the complete combustion or oxidation of allPage 6 of 40 petroleum products and natural gas liquids (ex refinery gate) minus non

- crude feedstocks and any biomass to be co

- processed with petroleum feedstocks. CO 2 i = Annual CO 2

CO emissions that would result from the complete combustion or oxidation of each petroleum product or natural gas liquid “i” (metric tons).

2 j = Annual CO 2

CO emissions that would result from the complete combustion or oxidation of each non

crude feedstock “j” (metric tons).

2 m = Annual CO 2

(e) emissions that would result from the complete combustion or oxidation of each type of biomass “m ” (metric tons). Summary calculation for importer and exporter products
. Importers and exporters shall calculate annual CO 2 emissions from all petroleum products and natural gas liquids imported or exported, respectively, using Equations MM

– 1 and MM

– 5 of this section.

Where:

CO 2 i = Annual CO 2

CO emissions that would result from the complete combustion or oxidation of each petroleum product or natural gas liquid “i” (metric tons).

2 x = Annual CO 2

(f) emissions that would result from the complete combustion or oxidation of all petroleum products and natural gas liquids. Emission factors for petroleum products and natural gas liquids
. The emission factor (EF i,j ) for each petroleum product and natural gas liquid shall be determined using either of the calc ulation methods described in paragraphs (f)(1) or (f)(2) ofPage 7 of 40
this section. The same calculation method must be used for the entire quantity of the product for the reporting year. For refiners, the quantity of a product that enters a refinery (i.e., a non

- cr ude feedstock) is considered separate from the quantity of a product ex refinery gate. (1) Calculation Method 1
. To determine the emission factor (i.e., EF i in Equation MM

– 1) for solid products, multiply the default carbon share factor (i.e., percent carbon by mass) in column B of Table MM

– 1 to this subpart for the appropriate product by 44/12. For all other products, use the default CO 2

(2) Ca lculation Method 2. emission factor listed in column C of Table MM

– 1 of this subpart for the appropriate product.

(i) For solid products, develop emission factors according to Equation MM

– 6 of this section using a value of 1 for density and direct measurements of carbon share according to methods set forth in §98.394(c). For all other products, dev elop emission factors according to Equation MM

– 6 of this section using direct measurements of density and carbon share according to methods set forth in §98.394(c).

Where:Page 8 of 40

EF i,j = Emission factor of the petroleum product or natural gas liquid (metric t ons CO 2 Density = Density of the petroleum product or natural gas liquid (metric tons per barrel for non

solid products, 1 for solid products). per barrel or per metric ton of product).

Carbon share = Percent of total mass that carbon represents in the pet roleum product or natural gas liquid, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation). 44/12 = Conversion factor for carbon to carbon dioxide. (ii) If you use a standard method that involves gas chromatography to determ ine the percent mass of each component in a product, calculate the product's carbon share using Equation MM

– 7 of this section.

Where:
Carbon Share = Percent of total mass that carbon represents in the petroleum product or natural gas liquid. % Composition i

%Mass * * *n = Percent of total mass that each molecular component in the petroleum product or natural gas liquid represents as determined by the procedures in the selected standard method.

i

(g) * * *n = Percent of total mass that carbon represent s in each molecular component of the petroleum product or natural gas liquid. Emission factors for biomass co

- processed with petroleum feedstocks
. Refiners shall use the most appropriatePage 9 of 40

default CO 2 emission factor (EF m ) for biomass in Table MM

– 2 of th is subpart to calculate CO 2

(h) emissions in paragraph (c) of this section. Special procedures for blended biomass

- based fuels

(1) A reporter using Calculation Method ology 1 to determine the emission factor of a petroleum product shall calculate the
CO . In the event that some portion of a petroleum product is biomass

based and was not derived by co

- processing biomass and petroleu m feedstocks together (i.e., the petroleum product was produced by blending a petroleum

- based product with a biomass

- based fuel), the reporting party shall calculate emissions for the petroleum product according to one of the methods in paragraphs (h)(1)
t hrough (h)(4) of this section, as appropriate.

2 emissions associated with that product using Equation MM

– 8 of this section in place of Equation MM

– 1 of this section.

Where:

CO 2 i = Annual CO 2

Product emissions that would result from the complete combustion or oxidation of each petroleum product “i” (metric tons).

i

EF = Annual volume of each petroleum product “i” produced, importe d, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate.

i = Petroleum product

- specific CO 2 emission factor (metric tons CO 2 per barrel) from Table MM

– 1 of this subpart.Page 10 of 40

%Vol i

(2) A refinery using Calculation Method ology 1 of this subp art to determine the emission factor of a non

- crude petroleum feedstock shall calculate the CO = Percent volume of product “i” that is petroleum

- based, not including any denaturant that may be present in any ethanol product, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation).

2 emissions associated with that feedstock using Equation MM

– 9 of this section in place of Equation MM

– 2 of this section.

Where:

CO 2 j = Annual CO 2

Feedstock emissions t hat would result from the complete combustion or oxidation of each non

crude feedstock “j” (metric tons).
j

EF = Annual volume of each petroleum product “j” that enters the refinery as a feedstock to be further refined or otherwise used on site (barr els).
j = Non

- crude petroleum feedstock

- specific CO 2 emission factor (metric tons CO 2 %Vol per barrel).
j

(3) Calculation Method 2 procedures for products. = Percent volume of feedstock “j” that is petroleum

- based, not including any denaturant that may be present in any ethanol product, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation).

(i) A reporter using Calculation Method 2 of this subpart to determine the emission factor of a petroleum product that does not contain denatured ethanol must calculate the CO 2Page 11 of 40 emissions associated with that product using Equation MM

– 10 of this section in place of Equation MM

– 1 of this section.

Where:

CO 2 i = Annual CO 2

Product emissions that would result from the complete combustion or oxidat ion of each product “i” (metric tons).

i

EF = Annual volume of each petroleum product “i” produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate.

i = Product

- specific CO 2 em ission factor (metric tons CO 2 EF per barrel).

m = Default CO 2

%Vol emission factor from Table MM

– 2 to subpart MM that most closely represents the component of product “i” that is biomass

based.

m

(ii) In the event that a petroleum product contains denatured ethanol, importers and exporters must follow Calculation Method 1 procedures in paragraph (h) (1) of this section; and refineries must sample the petroleum portion of the blended biomass

- based fuel prior to blending and calculate CO = Percent volume of petroleum product “i” that is biomass

- based, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation).

2 emissions using Equation MM

– 10a of this section.

Where:Page 12 of 40

CO 2 i = Annual CO 2

Product emissions that would result from the complete combustion or oxidation of each biomass

- blended fuel “i” (metric tons).

p

EF = Annual volume of the petroleum

- based portion of each biomass blended fuel “i” produced by the refiner (barrels).

i = Petroleum product

- specific CO 2 emission facto r (metric tons CO 2 (4) Calculation Method 2 procedures for non

- crude feedstocks. per barrel).

(i) A refiner using Calculation Method 2 of this subpart to determine the emission factor of a non

- crude petroleum feedstock that does not contain denatured ethan ol must calculate the CO 2 emissions associated with that feedstock using Equation MM

– 11 of this section in place of Equation MM

– 2 of this section.

Where:

CO 2 j = Annual CO 2

Feedstock emissions that would result from the complete combustion or oxidation of each non

crude feedstock “j” (metric tons).
j

EF = Annual volume of each petroleum product “j” that enters the refinery to be further refined or otherwise used on site (barrels).
j = Feedstock

- specific CO 2 emission factor (metric tons CO 2 EF per barrel).

m = Default CO 2

%Vol emission factor from Table MM

– 2 to subpart MM that most closely represents the component of petroleum product “j” that is biomass

- based.

m = Percent volume of non

- crude feedstock “j” that is biomass

- based, expressed as a fraction (e.g., 7 5% would be expressed as 0.75 in the above equation).Page 13 of 40
(ii) In the event that a non

- crude feedstock contains denatured ethanol, refiners must follow Calculation Method 1 procedures in paragraph (h)(2) of this section. (i) Optional procedures for blended pro ducts that do not contain biomass. (1) In the event that a reporter produces, imports, or exports a blended product that does not include biomass, the reporter may calculate emissions for the blended product according to the method in paragraph (i)(2) of t his section. In the event that a refiner receives a blended non

- crude feedstock that does not include biomass, the refiner may calculate emission for the blended non

- crude feedstock according to the method in paragraph (i)(3) of this section. The procedure s in this section may be used only if all of the following criteria
are met: (i) The reporter knows the relative proportion of each component of the blend (i.e., the mass or volume percentage). (ii) Each component of blended product “i” or blended non

crud e feedstock “j” meets the strict definition of a product listed in Table MM

– 1 to subpart MM. (iii) The blended product or non

- crude feedstock is not comprised entirely of natural gas liquids. (iv) The reporter uses Calculation Method 1.Page 14 of 40 (v) Solid component s are blended only with other solid components. (2) The reporter must calculate emissions for the blended product using Equation MM

– 12 of this section in place of Equation MM

– 1 of this section.

Where:

CO 2 i = Annual CO 2
Blending Component emissions that would result from the complete combustion or oxidation of a blended product “i” (metric tons).

i...n

EF = Annual volume or mass of each blending component that is blended (barrels or metric tons).

i...n = CO 2 emission factors specific to each blending compo nent (metric tons CO 2

n = Number of blending components blended into blended product “i”. per barrel or per metric ton of product).

(3) For refineries, the reporter must calculate emissions for the blended non

- crude feedstock using Equation MM

– 13 of this

s ection in place of Equation MM

– 2 of this section.

Where:

CO 2 j = Annual CO 2
Blending Component emissions that would result from the complete combustion or oxidation of a blended non - crude feedstock “j” (metric tons).

i...n = Annual volume or mass of each blending component that is blended (barrels or metric tons).Page 15 of 40

EF i...n = CO 2 emission factors specific to each blending component (metric tons CO 2

n = Number of blending components blended into blended non

- crude fee dstock “j”. per barrel or per metric ton of product).

(4) For refineries, if a blending component “k” used in paragraph (i)(2) of this section enters the refinery before blending as non

- crude feedstock: (i) The emissions that would result from the complete combustion or oxidation of non

- crude feed stock “k” must still be calculated separately using Equation MM

– 2 of this section and applied in Equation MM

– 4 of this section. (ii) The quantity of blending component “k” applied in Equation MM

– 12 of this section and the quantity of non

- crude feedstock “k ” applied in Equation MM

– 2 of this section must be determined using the same method or practice.

(a) Determination of quantity. § 98.394 Monitoring and QA/QC requirements.

(1) The quantity of petroleum products, natural gas liquids, and biomass, as well a s the quantity of crude oil measured on site at a refinery, shall be determined as follows: (i) Where an appropriate standard method published by a

consensus - based standards organization exists, such a method shall be used. Consensus

- based standards organizations include, but are not limited to, the following: ASTM International, thePage 16 of 40
American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (A PI), and the North American Energy Standards Board (NAESB). (ii) Where no appropriate standard method developed by a

consensus - based standards organization exists, industry standard practices shall be followed. (iii) For products that are liquid at 60 degr ees Fahrenheit and one standard atmosphere, all measurements of quantity shall be temperature

- adjusted and pressure

- adjusted to these conditions. For all other products, reporters shall use appropriate standard conditions specified in the standard method; if temperature and pressure conditions are not specified in the standard method or if a reporter uses an industry standard practice to determine quantity, the reporter shall use appropriate standard conditions according to established industry practices. ( 2) All measurement equipment (including, but not limited to, flow meters and tank gauges) used for compliance with this subpart shall be appropriate for the standard method or industry standard practice followed under paragraph (a)(1)(i) or (a)(1)(ii) of t his section. (3) The annual quantity of crude oil not measured on site at a refinery received shall be determined according to one ofPage 17 of 40 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. (b) Equipment Calibration. (1) All measurement equipment shall be calibrated prior to its first use for reporting under this subpart, using an appropriate standard method published by a consensus based standards organization or according to the equipment manufacturer's directions. (2) Measurement equipment shall be recalibrated at the minimum frequency specified by the standard method used or by the equipment manufacturer's directions. (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 int erim. Such postponements shall be documented in the monitoring plan that is required under §98.3(g)(5). (c) Procedures for Calculation Method ology 2 of this subpart.Page 18 of 40 (1) Reporting parties shall collect one sample of each petroleum product or natural gas li quid on any day of each calendar month of the reporting year in which the quantity of that product was measured in accordance with the requirements of this subpart. For example, if a given product was measured as entering the refinery continuously througho ut the reporting year, twelve samples of that product shall be collected over the reporting year, one on any day of each calendar month of that year. If a given product was only measured from April 15 through June 10 of the reporting year, a refiner would collect three samples during that year, one during each of the calendar months of April, May and June on a day when the product was measured as either entering or exiting the refinery. Each sample shall be collected using an appropriate standard method pub lished by a

consensus - based standards organization. (2) Mixing and handling of samples shall be performed using an appropriate standard method published by a consensus

- based standards organization. (3) Density measurement. (i) For all products that are not solid, reporters shall test for density using an appropriate standard method published by a consensus

- based standards organization. (ii) The density value for a given petroleum product shall be generated by either making a physical composite of all of thePage 19 of 40 samples collected for the reporting year and testing that single sample or by measuring the individual samples throughout the year and defining the representative density value for the sample set by numerical means , i.e., a mathematical composite. If a ph ysical composite is chosen as the option to obtain the density value, the reporter shall submit each of the individual samples collected during the reporting year to the laboratory responsible for generating the composite sample. (iii) For physical composi tes, the reporter shall handle the individual samples and the laboratory shall mix them in accordance with an appropriate standard method published by a

consensus - based standards organization. (iv) All measurements of density shall be temperature

adjusted and pressure

- adjusted to the conditions assumed for determining the quantities of the product reported under this subpart. (4) Carbon share measurement. (i) Reporters shall test for carbon share using an appropriate standard method published by a consensus

- based standards organization. (ii) If a standard method that involves gas chromatography is used to determine the percent mass of each component in a product, the molecular formula for each component shall be obtained from the information provided in the standard methodPage 20 of 40 and the atomic mass of each element in a given molecular component shall be obtained from the periodic table of the elements. (iii) The carbon share value for a given petroleum product shall be generated by either making a physical composit e of all of the samples collected for the reporting year and testing that single sample or by measuring the individual samples throughout the year and defining the representative carbon share value for the sample set by numerical means , i.e., a mathematica l composite. If a physical composite is chosen as the option to obtain the carbon share value, the reporter shall submit each of the individual samples collected during the reporting year to the laboratory responsible for generating the composite sample. ( iv) For physical composites, the reporter shall handle the individual samples and the laboratory shall mix them in accordance with an appropriate standard method published by a

consensus - based standards organization. (d) Measurement of API gravity and sulf ur content of crude oil. (1) A representative sample or multiple representative samples of each batch of crude oil shall be taken 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.Page 21 of 40 (2) Samples shall be handled 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) API gravity shall be measured 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. The weighted aver age API gravity for each batch shall be calculated by multiplying the volume associated with each representative sample by the API gravity, adding these values for all the samples, and then dividing that total value by the volume of the batch. (4) Sulfur c ontent shall be measured 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. The weighted average sulfur content for each batch shall be calculated by multiplying the volume associated with each representative sample by the sulfur content, adding these values for all the samples, and then dividing that total value by the volume of the batch. (5) All measurements shall be temp erature

- adjusted and
pressure - adjusted to the conditions assumed for determining the quantities of crude oil reported under this subpart. (d) [Reserved]Page 22 of 40

(a) § 98.395 Procedures for estimating missing data. Determination of quantity

(1) For quantities of a product that are purchased or sold, a period of missing data shall be substituted using a reporter's established procedures for billing purposes in that period as agreed to by th e party selling or purchasing the product. . 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:

(2) For quantities of a product that are not purchased or sold but of which the custody is transferred, a period of missing data shall be substituted using a reporter's established procedures for tracking purposes in that period as agreed to by the party involved in custody transfer of the product. (b) Determination of emission factor

(c) . Whenever any of the procedures in §98.394(c) cannot be followed to develop an emission factor for any reason, Calculation Method olo gy 1 of this subpart must be used in place of Calculation Method ology 2 of this subpart for the entire reporting year. 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 thePage 23 of 40 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 in cident, 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. (c) [Reserved]

In addition to the information requir ed by §98.3(c), the following requirements apply: § 98.396 Data reporting requirements.

(a) Refiners shall report the following information for each facility: (1) For each petroleum product or natural gas liquid listed in table MM

– 1 of this subpart that enters the refinery to be further refine d 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 produc t. (1) [Reserved]
. (2) 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 annualPage 24 of 40 quantity in metric tons or barrels. For natural gas liquids , quantity shall reflect the individual components of the product. (3) For each feedstock reported in paragraph (a)(2) of this section that was produced by blending a petroleum

- based product with a biomass

- based product, report the percent of the vo lume reported in paragraph (a)(2) of this section that is petroleum

based (excluding any denaturant that may be present in any ethanol product). (4) Each standard method or other industry standard practice used to measure each quantity reported in paragrap h (a)( 1 2 ) of this section. (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 st andard 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]
. (6) 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. For natural gas liquids, quantity shall reflect the individual components of thePage 25 of 40 product. Petroleum products and natural gas liquids that enter the refinery, but are not reported in (a)(2), shall not be reported under this paragraph. (7) For each product reported in paragraph (a)(6) of this section that was produced by blending a petroleum

- based product with a biomass

- based product, report the percent of the volume reported in paragraph (a)(6) of this section that is petroleum

based (excluding any denaturant that may be present in any ethanol product). (8) Each standard method or o ther industry standard practice used to measure each quantity reported in paragraph (a)( 5 6 ) of this section. (9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Method ology 2 of this subpart was used to determine an e missions factor, report: (i) The number of samples collected according to §98.394(c) (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 emi ssions factor in metric tons CO 2

(10) For every non

- solid feedstock reported in paragraph (a)(2) of this section for which Calculation Method ology 2 of this subpart was used to determine an emissions factor, report: per barrel or per metric ton of product
.Page 26 of 40 (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (11) For every petroleum product and natural gas liquid reported in paragraph (a)(6) of this section for which Calculation Method ology 2 of this subpart was used to determine an emissions factor, report: (i) The number of samples collected according to §98.394(c). (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 emissions factor in metric tons CO 2

(12) For every non

- solid petroleum product and natural gas liquid reported in paragraph (a)(6) for which Calcula tion Method 2 was used to determine an emissions factor, report: per barrel or per metric ton of product.

(i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (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.Page 27 of 40
(13) [Reserved]
. (1 4) 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. (15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)( 13 1 4 ) of this section. (16) The CO 2

(17) The CO emissions in metric tons that would result from the complete combustion or oxidation of each petroleum product and natur al gas liquid (ex refinery gate) reported in paragraph (a)(6) of this section that were calculated according to §98.393(a) or (h).

2

(18) The CO emissions in metric tons that would result from the complete combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section that were calculated according to §98.393(b) or (h).

2 emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co

- processed with petroleum feedsto cks reported in paragraph (a)( 13 1 4 ) of this section, calculated according to §98.393(c).Page 28 of 40
(19) The sum of CO 2

(20) For all crude oil t hat enters the refinery, report the annual quantity in barrels. All of the following information for all crude oil feedstocks used at the refinery: emissions that would result from the complete combustion or oxidation of all products, calculated according to §98.393(d).

(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. (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. (22) Volume of crude oil in barrels that you injected into a crude oil supply or reservoir. A volume of crude oil thatPage 29 of 40 entered the refinery, but was not reported in paragraphs (a)(2) or (a)(20), shall not be reported under this paragraph. (23) Special provisions for 2010

(23) [Reserved] . For reporting year 2010 only, a refiner that knows the informat ion 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 bat ch information under paragraph 98.396(a)(20).

(b) In addition to the information required by §98.3(c), each importer shall report all of the following information at the corporate level: (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]
. (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, quantityPage 30 of 40 shall reflect the individual components of the p roduct
. as listed in Table MM

– 1 of this subpart. (3) For each product reported in paragraph (b)(2) of this section that was produced by blending a petroleum

- based product with a biomass

- based product, report the percent of the volume reported in paragraph (b)(2) of this section that is petroleum

based (excluding any denaturant that may be present in any ethanol product). (4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)( 1 2 ) of this section. (5) For each product reported in paragraph (b)(2) of this section for which Calculation Method ology 2 of this subpart used was used to determine an emissions factor, report: (i) The number of samples collected according to §98.394(c). (ii) The sampling sta ndard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 emissions factor in metric tons CO 2

(6) For each non

- solid product r eported in paragraph (b)(2) of this section for which Calculation Method ology 2 of this subpart was used to determine an emissions factor, report: per barrel or per metric ton of product.Page 31 of 40 (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (7) Th e CO 2

(8) The sum of CO emissions in metric tons that would result from the complete combustion or oxidation of each imported petroleum product and natural gas liquid reported in paragraph (b)(2) of this section, calculated according to §98.393(a).

2

(c) In addition to the information required by §98.3(c), each exporter shall report all of the following information at the corporate level: emissi ons that would result from the complete combustion oxidation of all imported products, calculated according to §98.393(e).

(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]
. (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 liqui ds, quantity shall reflect the individual components of the product.Page 32 of 40 (3) For each product reported in paragraph (c)(2) of this section that was produced by blending a petroleum

- based product with a biomass

- based product, report the percent of the volume

re ported in paragraph (c)(2) of this section that is petroleum based (excluding any denaturant that may be present in any ethanol product). (4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)( 1 2 ) of this section. (5) For each product reported in paragraph (c)(2) of this section for which Calculation Method ology 2 of this subpart was used to determine an emissions factor, report: (i) The number of samples collected according to §98.394(c). (ii) T he sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 emissions factor in metric tons CO 2

(6) For each non

- solid product reported in paragraph (c)(2) of this section for which Calculation Method ology 2 of this subpart used was used to determine an emissions factor, report: per barrel or per metric ton of product.

(i) The density test results in metric tons per barrel. (ii) The standard method used to test density.Page 33 of 40
(7) The CO 2

(8) The sum of CO emissions in metric tons that would result from the complete combustion or oxidation of for each exported petroleum product and natural gas liquid reported in paragraph (c)(2) of this section, calculated according to §98.393(a).

2

(d) emissions that would result from the complete combustion or oxidation of all exported products, calculated according to §98.393(e). Blended non

- crude feedstock and products

(i) Volume or mass of each blending component. . (1) Refineries, exporters, and importers must report the following information for each blended product and non

- crude feedstock where emissions were calculated according to §98.393(i):

(ii) The CO 2

(iii) Whether it is a blended non

- crude feedstock or a blended product. emissions i n metric tons that would result from the complete combustion or oxidation of each blended non

- crude feedstock or product, using Equation MM

– 12 or Equation MM

– 13 of this section.

(2) Fo r 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 component s of the blended non

- crude feedstock.Page 34 of 40 (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.

(a) All reporters shall retain copies of all reports submitted to EPA under §98.396. In addition, all reporters shal l maintain sufficient records to support information contained in those reports, including but not limited to information on the characteristics of their feedstocks and products. § 98.397 Records that must be retained.

(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 liqui ds, 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 initi al calibration and the frequency of recalibration for the measurement equipment used.Page 35 of 40 (c) Reporters shall retain laboratory reports, calculations and worksheets used to estimate the CO 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 CO emissions of the quantities of petroleum products, natural gas liquids , biomass, and feedstocks reported under this subpart.

2

(e) Estimates of missing data shall be documented and records maintained showing the calculations. emissions were calculated using Calculation Method ology 2.

(f) Reporters described in this subpart shall also retain all records described in §98.3(g).

Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. § 98.398 Defini tions.

Bulk NGLs for purposes of reporting under this subpart means mixtures of NGLs that are sold or delivered as undifferentiated product. 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 orPage 36 of 40 delivered as differentiated product. Generally, such liquids consist of ethane, propane, butanes, or pentanes plus. Batch means

(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. 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:

(2) Up to an annual volume of a type of crude oil identified by a generic name for the crude stream and an appropriate E IA 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.Page 37 of 40

**Table MM –**  **1 to Subpart MM of Part 98**  **— Default Factors for**  **Petroleum Products and Natural Gas Liquids**

**Products 12** 

**Column A: density**  **(metric tons/bbl)**  **Column B: carbon**  **share (% of**  **mass) Column C:**  **emission factor (metric tons**  CO 2 **Finished Motor Gasoline** / **bbl)**

Conventional

— Summer Regular 0.1181 86.66 0.3753 Midgrade 0.1183 86.63 0.3758 Premium 0.1185 86.61 0.3763 Conventional

— Winter Regular 0.1155 86.50 0.3663 Midgrade 0.1161 86.55 0.3684 Premium 0.1167 86.59 0.3705 Reformulated

— Summer Regular 0.1167 86.13 0.3686 Midgrade 0.1165 86.07 0.3677 Premium 0.1164 86.00 0.3670 Reformulated

— Winter Regular 0.1165 86.05 0.3676 Midgrade 0.1165 86.06 0.3676 Premium 0.1166 86.06 0.3679 Gasoline

— Other 0.1185 86.61 0.3763 Blendstocks CBOB

— Summer Regular 0.1181 86.66 0.3753 Midgrade 0.1183 86.63 0.3758 Premium 0.1185 86.61 0.3763 CBOB

— Winter Regular 0.1155 86.50 0.3663 Midgrade 0.1161 86.55 0.3684 Premium 0.1167 86.59 0.3705Page 38 of 40

**Products Column A:**  **density (metric**  **tons/bbl) Column B:**  **carbon share**  **(% of mass)**  **Column C: emission factor**  **(metric tons** CO 2 RBOB

— Summer / **bbl)**

Regular 0.1167 86.13 0.3686 Midgrade 0.1165 86.07 0.3677 Premium 0.1164 86.00 0.3670 RBOB

— Winter Regular 0.1165 86.05 0.3676 Midgrade 0.1165 86.06 0.3676 Premium 0.1166 86.06 0.3679 Blendstocks

— Other 0.1185 86.61 0.3763 Oxygenates Methanol 0.1268 37.48 0.1743 GTBA 0.1257 64.82 0.2988 MTBE 0.1181 68.13 0.2950 ETBE 0.1182 70.53 0.3057 TAME 0.1229 70.53 0.3178 DIPE 0.1156 70.53 0.2990 Distillate Fuel Oil Distillate No. 1 Ultra Low Sulfur 0.1346 86.40 0.4264 Low Sulfur 0.1346 86.40 0.4264 High Sulfur 0.1346 86.40 0.4264 Distillate No. 2 Ultra Low Sulfur 0.1342 87.30 0.4296 Low Sulfur 0.1342 87.30 0.4296 High Sulfur 0.1342 87.30 0.4296 Distillate Fuel Oil No. 4 0.1452 86.47 0.4604 Residual Fuel Oil No. 5 (Navy Special) 0.1365 85.67 0.4288
Residual Fuel Oil No. 6 0.1528 84.67 0.4744Page 39 of 40

**Products Column A:**  **density (metric**  **tons/bbl) Column B:**  **carbon share**  **(% of mass)**  **Column C: emission factor**  **(metric tons** CO 2 (a.k.a. Bunker C) / **bbl)**

Kerosene

- Type Jet Fuel 0.1294 86.30 0.4095 Kerosene 0.1346 86.40 0.4264 Diesel

— Other 0.1452 86.47 0.4604 Petrochemical Feedstocks Naphthas (< 401 °F) 0.1158 84.11 0.3571 Other Oils (> 401 °F) 0.1390 87.30 0.4450 Unfinished Oils Heavy Gas Oils 0.1476 85.80 0.4643 Residuum 0.1622 85.70 0.5097 Other Petroleum Products and Natural Gas Liquids Aviation Gasoline 0.1120 85.00 0.3490 Special Naphthas 0.1222 84.76 0.3798 Lubricants 0.1428 85.80 0.4492 Waxes 0.1285 85.30 0.4019 Petroleum Coke 0.1818 92.28 0.6151 Asphalt and Road Oil 0.1634 83.47 0.5001 Still Gas 0.1405 77.70 0.4003 Ethane 0. 0866 0579 3 79.89 0. 2537 1 70 Ethylene 0. 0903 0492 4 85.63 0. 2835 154 Propane 0. 0784 0806 3 81.71 0. 2349 241 Propylene 0. 0803 0827 3 85.63 0. 2521 2 60 Butane 0. 0911 0928 3 82.66 0. 2761 281 Butylene 0. 0935 0972 3 85.63 0. 2936 30 5 Isobutane 0. 0876 0892 3 82.66 0. 2655 270 Isobutylene 0. 0936 0949 3 85.63 0. 2939 29 8 Pentanes Plus 0.1055 83.63 0.3235 Miscellaneous Products 0.1380 85.49 0.4326Page 40 of 40

1 In the case of products blended with some portion of biomass

based fuel, the carbon share in Table MM

– 1 of this subpart represents only the petroleum

- based components. 2 Products that are derived entirely from biomass should not be reported, but products that were derived from both biomass and a petroleum product (i.e., co

- processed) should be reported as the petroleum product that it most closely represents. 3 The density and emission factors for components of LPG determined at 60 oF and saturation pressure (LPGs other than ethylene) 4 The density and emission factor for ethylene determined at 41oF and saturation pressure.
**Table MM –**  **2 to Subpart MM of Part 98 —**  **Default Factors for Biomass**   ** Based Fuels and Biomass**

**Biomass -**  **based fuel and biomass**  **Column A: Density**  **(metric tons/bbl)**  **Column B: Carbon share**  **(% of mass) Column C:**  **Emission factor (metric tons**  CO 2 Ethanol (100%) / **bbl)** 0.1267 52.14 0.2422 Biodiesel (100%, methyl ester) 0.1396 77.30 0.3957
Rendered Animal Fat 0.1333 76.19 0.3724 Vegetable Oil 0.1460 76.77 0.4110