(a) A hydrogen production source category consists of facilities that produce hydrogen gas as a product.

(b) This source category comprises process units that produce hydrogen by reforming, gasification, oxidation, reaction, or other transformations of feedstocks except the processes listed in paragraph (b)(1) or (2) of this section.

(1) Any process unit for which emissions are reported under another subpart of this part. This includes, but is not necessarily limited to:

(i) Ammonia production units for which emissions are reported under subpart G.

(ii) Catalytic reforming units at petroleum refineries that transform naphtha into higher octane aromatics for which emissions are reported under subpart Y.

(iii) Petrochemical process units for which emissions are reported under subpart X.

(2) Any process unit that only separates out diatomic hydrogen from a gaseous mixture and is not associated with a unit that produces hydrogen created by transformation of one or more feedstocks, other than those listed in paragraph (b)(1) of this section.

(c) This source category includes the process units that produce hydrogen and stationary combustion units directly associated with hydrogen production (e.g. , reforming furnace and hydrogen production process unit heater).

You must report GHG emissions under this subpart if your facility contains a hydrogen production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).

You must report:

(a) CO2 emissions from each hydrogen production process unit, including fuel combustion emissions accounted for in the calculation methodologies in § 98.163.

(b) [Reserved]

(c) CO2, CH4, and N2O emissions from each stationary combustion unit other than hydrogen production process units. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(d) For CO2 collected and transferred off site, you must follow the requirements of subpart PP of this part.

You must calculate and report the annual CO2 emissions from each hydrogen production process unit using the procedures specified in paragraphs (a) through (c) of this section, as applicable.

(a) Continuous Emissions Monitoring Systems (CEMS). Calculate and report under this subpart the 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).

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

(1) Gaseous fuel and feedstock. You must calculate the annual CO2 emissions from each gaseous fuel and feedstock according to Equation P-1 of this section:

(2) Liquid fuel and feedstock. You must calculate the annual CO2 emissions from each liquid fuel and feedstock according to Equation P-2 of this section:

(3) Solid fuel and feedstock. You must calculate the annual CO2 emissions from each solid fuel and feedstock according to Equation P-3 of this section:

(c) If GHG emissions from a hydrogen production process unit are vented through the same stack as any combustion unit or process equipment that reports CO2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part, then the owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part. If GHG emissions from a hydrogen production process unit using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part does not include combustion emissions from the hydrogen production unit (i.e. , the hydrogen production unit has separate stacks for process and combustion emissions), then the calculation methodology in paragraph (b) of this section shall be used considering only fuel inputs to calculate and report CO2 emissions from fuel combustion related to the hydrogen production unit.

The GHG emissions data for hydrogen production process units must be quality-assured as specified in paragraph (a) or (b) of this section, as appropriate for each process unit, except as provided in paragraph (c) of this section:

(a) If a CEMS is used to measure GHG emissions, then the facility must comply with the monitoring and QA/QC procedures specified in § 98.34(c).

(b) If a CEMS is not used to measure GHG emissions, then you must:

(1) Calibrate all oil and gas flow meters that are used to measure liquid and gaseous fuel and feedstock volumes (except for gas billing meters) according to the monitoring and QA/QC requirements for the Tier 3 methodology in § 98.34(b)(1). Perform oil tank drop measurements (if used to quantify liquid fuel or feedstock consumption) according to § 98.34(b)(2). Calibrate all solids weighing equipment according to the procedures in § 98.3(i).

(2) Determine the carbon content and the molecular weight annually of standard gaseous hydrocarbon fuels and feedstocks having consistent composition (e.g., natural gas) according to paragraph (b)(5) of this section. For gaseous fuels and feedstocks that have a maximum product specification for carbon content less than or equal to 0.00002 kg carbon per kg of gaseous fuel or feedstock, you may instead determine the carbon content and the molecular weight annually using the product specification's maximum carbon content and molecular weight. For other gaseous fuels and feedstocks (e.g., biogas, refinery gas, or process gas), sample and analyze no less frequently than weekly to determine the carbon content and molecular weight of the fuel and feedstock according to paragraph (b)(5) of this section.

(3) Determine the carbon content of fuel oil, naphtha, and other liquid fuels and feedstocks at least monthly, except annually for standard liquid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for liquid fuels and feedstocks delivered by bulk transport (e.g., by truck or rail) according to paragraph (b)(5) of this section. For liquid fuels and feedstocks that have a maximum product specification for carbon content less than or equal to 0.00006 kg carbon per gallon of liquid fuel or feedstock, you may instead determine the carbon content annually using the product specification's maximum carbon content.

(4) Determine the carbon content of coal, coke, and other solid fuels and feedstocks at least monthly, except annually for standard solid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for solid fuels and feedstocks delivered by bulk transport (e.g., by truck or rail) according to paragraph (b)(5) of this section.

(5) Except as provided in paragraphs (b)(2) and (3) of this section for fuels and feedstocks with a carbon content below the specified levels, you must use the following applicable methods to determine the carbon content for all fuels and feedstocks, and molecular weight of gaseous fuels and feedstocks. Alternatively, you may use the results of chromatographic analysis of the fuel and feedstock, provided that the chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the chromatograph are documented in the written monitoring plan for the unit under § 98.3(g)(5).

(i) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(ii) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).

(iii) ASTM D2013-07 Standard Practice of Preparing Coal Samples for Analysis (incorporated by reference, see § 98.7).

(iv) ASTM D2234/D2234M-07 Standard Practice for Collection of a Gross Sample of Coal (incorporated by reference, see § 98.7).

(v) ASTM D2597-94 (Reapproved 2004) Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography (incorporated by reference, see § 98.7).

(vi) ASTM D3176-89 (Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7).

(vii) ASTM D3238-95 (Reapproved 2005), Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method (incorporated by reference, see § 98.7).

(viii) ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum and Petroleum Products (incorporated by reference, see § 98.7).

(ix) ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products (incorporated by reference, see § 98.7).

(x) ASTM D5291-02 (Reapproved 2007), Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see § 98.7).

(xi) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).

(xii) ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal (incorporated by reference, see § 98.7).

(xiii) ASTM D6883-04 Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles (incorporated by reference, see § 98.7).

(xiv) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of Coal (incorporated by reference, see § 98.7).

(xv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).

(xvi) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see § 98.7).

(xvii) ISO 3170: Petroleum Liquids—Manual sampling—Third Edition (incorporated by reference, see § 98.7).

(xviii) ISO 3171: Petroleum Liquids—Automatic pipeline sampling—Second Edition (incorporated by reference, see § 98.7).

(xix) For fuels and feedstocks with a carbon content below the specified levels in paragraphs (b)(2) and (3) of this section, if the methods listed in paragraphs (b)(5)(i) through (xviii) of this section are not appropriate because the relevant compounds cannot be detected, the quality control requirements are not technically feasible, or use of the method would be unsafe, you may use modifications of the methods listed in paragraphs (b)(5)(i) through (xviii) or use other methods that are applicable to your fuel or feedstock.

(c) You may use best available monitoring methods as specified in paragraph (c)(2) of this section for measuring the fuel used by each stationary combustion unit directly associated with hydrogen production (e.g., reforming furnace and hydrogen production process unit heater) that meets the criteria specified in paragraph (c)(1) of this section. Eligibility to use best available monitoring methods ends upon the completion of any planned process unit or equipment shutdown after January 1, 2025.

(1) To be eligible to use best available monitoring methods, you must meet all criteria in paragraphs (c)(1)(i) through (iv) of this section.

(i) The stationary combustion unit must be directly associated with hydrogen production (e.g., reforming furnace and hydrogen production process unit heater).

(ii) A measurement device meeting the requirements in paragraph (b)(1) of this section is not installed to measure the fuel used by each stationary combustion unit as of January 1, 2025.

(iii) The hydrogen production unit and associated stationary combustion unit are operated continuously.

(iv) Installation of a measurement device to measure the fuel used by each stationary combustion unit that meets the requirements in paragraph (b)(1) of this section must require a planned process equipment or unit shutdown or can only be done through a hot tap.

(2) Best available monitoring methods means any of the following methods:

(i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart.

(ii) Supplier data.

(iii) Engineering calculations.

(iv) Other company records.

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 (e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter must be used in the calculations as specified in paragraphs (a), (b), and (c) of this section:

(a) For each missing value of the monthly fuel and feedstock consumption, the substitute data value must be the best available estimate of the fuel and feedstock consumption, based on all available process data (e.g., hydrogen production, electrical load, and operating hours). You must document and keep records of the procedures used for all such estimates.

(b) For each missing value of the carbon content or molecular weight of the fuel and feedstock, the substitute data value must be the arithmetic average of the quality-assured values of carbon contents or molecular weight of the fuel and feedstock immediately preceding and immediately following the missing data incident. If no quality-assured data on carbon contents or molecular weight of the fuel and feedstock are available prior to the missing data incident, the substitute data value must be the first quality-assured value for carbon contents or molecular weight of the fuel and feedstock obtained after the missing data period. You must document and keep records of the procedures used for all such estimates.

(c) For missing CEMS data, you must use the missing data procedures in § 98.35.

In addition to the information required by § 98.3(c), each annual report must contain the following information for each hydrogen production process unit:

(a) The unit identification number.

(b) If a CEMS is used to measure CO2 emissions, then you must report the relevant information required under § 98.36 for the Tier 4 Calculation Methodology. If the CEMS measures emissions from either a common stack for multiple hydrogen production units or a common stack for hydrogen production unit(s) and other source(s), you must also report the estimated decimal fraction of the total annual CO2 emissions attributable to this hydrogen production process unit (estimated using engineering estimates or best available data).

(c) If a material balance is used to calculate emissions using equations P-1 through P-3 to § 98.163, as applicable, report the total annual CO2 emissions (metric tons) and the name and annual quantity (metric tons) of each carbon-containing fuel and feedstock.

(d) The information specified in paragraphs (d)(1) through (10):

(1) The type of hydrogen production unit (steam methane reformer (SMR) only, SMR followed by water gas shift reaction (WGS), partial oxidation (POX) only, POX followed by WGS, autothermal reforming only, autothermal reforming followed by WGS, water electrolysis, brine electrolysis, other (specify)).

(2) The type of hydrogen purification method (pressure swing adsorption, amine adsorption, membrane separation, other (specify), none).

(3) Annual quantity of hydrogen produced by reforming, gasification, oxidation, reaction, or other transformation of feedstocks (metric tons).

(4) Annual quantity of hydrogen that is purified only (metric tons). This quantity may be assumed to be equal to the annual quantity of hydrogen in the feedstocks to the hydrogen production unit.

(5) Annual quantity of ammonia intentionally produced as a desired product, if applicable (metric tons).

(6) Quantity of CO2 collected and transferred off site in either gas, liquid, or solid forms, following the requirements of subpart PP of this part.

(7) Annual quantity of carbon other than CO2 or methanol collected and transferred off site or transferred to a separate process unit within the facility for which GHG emissions associated with this carbon is being reported under other provisions of this part, in either gas, liquid, or solid forms (metric tons carbon).

(8) Annual quantity of methanol intentionally produced as a desired product, if applicable, (metric tons) for each process unit.

(9) Annual net quantity of steam consumed by the unit, (metric tons). Include steam purchased or produced outside of the hydrogen production unit. If the hydrogen production unit is a net producer of steam, enter the annual net quantity of steam consumed by the unit as a negative value.

(10) An indication (yes or no) if best available monitoring methods were used, in accordance with § 98.164(c), to determine fuel flow for each stationary combustion unit directly associated with hydrogen production (e.g., reforming furnace and hydrogen production process unit heater). If yes, report:

(i) The beginning date of using best available monitoring methods, in accordance with § 98.164(c), to determine fuel flow for each stationary combustion unit directly associated with hydrogen production (e.g., reforming furnace and hydrogen production process unit heater).

(ii) The anticipated or actual end date of using best available monitoring methods, as applicable, in accordance with § 98.164(c), to determine fuel flow for each stationary combustion unit directly associated with hydrogen production (e.g., reforming furnace and hydrogen production process unit heater).

In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section for each hydrogen production facility.

(a) If a CEMS is used to measure CO2 emissions, then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37, and, if the CEMS measures emissions from a common stack for multiple hydrogen production units or emissions from a common stack for hydrogen production unit(s) and other source(s), records used to estimate the decimal fraction of the total annual CO2 emissions from the CEMS monitoring location attributable to each hydrogen production unit.

(b) You must retain records of all analyses and calculations conducted to determine the values reported in § 98.166(b).

(c) [Reserved]

(d) The owner or operator must document the procedures used to ensure the accuracy of the estimates of fuel and feedstock usage in § 98.163(b), including, but not limited to, calibration of weighing equipment, fuel and feedstock flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.

(e) The applicable verification software records as identified in this paragraph (e). You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (e)(1) through (12) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (e)(1) through (12) of this section for each hydrogen production unit.

(1) Indicate whether the monthly consumption of each gaseous fuel or feedstock is measured as mass or volume (Equation P-1 of § 98.163).

(2) Monthly volume of the gaseous fuel or feedstock (scf at standard conditions of 68 °F and atmospheric pressure) (Equation P-1).

(3) Monthly mass of the gaseous fuel or feedstock (kg of fuel or feedstock) (Equation P-1).

(4) Average monthly carbon content of the gaseous fuel or feedstock (kg C per kg of fuel or feedstock) (Equation P-1).

(5) Average monthly molecular weight of the gaseous fuel or feedstock (kg/kg-mole) (Equation P-1).

(6) Indicate whether the monthly consumption of each liquid fuel or feedstock is measured as mass or volume (Equation P-2 of § 98.163).

(7) Monthly volume of the liquid fuel or feedstock (gallons of fuel or feedstock) (Equation P-2).

(8) Monthly mass of the liquid fuel or feedstock (kg of fuel or feedstock) (Equation P-2).

(9) Average monthly carbon content of the liquid fuel or feedstock (kg C per gallon of fuel or feedstock) (Equation P-2).

(10) Average monthly carbon content of the liquid fuel or feedstock (kg C per kg of fuel or feedstock) (Equation P-2).

(11) Monthly mass of solid fuel or feedstock (kg of fuel and feedstock) (Equation P-3 of § 98.163).

(12) Average monthly carbon content of the solid fuel or feedstock (kg C per kg of fuel and feedstock) (Equation P-3).

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.