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Subpart P—Hydrogen Production

§ 98.160 Definition of the source category.

(a) A hydrogen production source category consists of 

facilities that produce hydrogen gas sold as a product to other 

entities. 

(b) This source category comprises process units that 

produce hydrogen by reforming, gasification, oxidation, 

reaction, or other transformations of feedstocks.

(c) This source category includes merchant hydrogen 

production facilities located within another facility if they 

are not owned by, or under the direct control of, the other 

facility's owner and operator. 

§ 98.161 Reporting threshold.

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).

§ 98.162 GHGs to report.

You must report:

(a) CO2 emissions from each hydrogen production process 

unit.

(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 
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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.

§ 98.163 Calculating GHG emissions.

You must calculate and report the annual CO2 emissions from 

each hydrogen production process unit using the procedures 

specified in either paragraph (a) or (b) of this section.

(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 hydrogen 

production by following paragraphs (b)(1) through (b)(3) of this 

section. The carbon content and molecular weight shall be 

obtained from the analyses conducted in accordance with 

§98.164(b)(2), (b)(3), or (b)(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 
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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:

Where:

CO2 = Annual CO2 process emissions arising from fuel 

and feedstock consumption (metric tons/yr).

Fdstkn = Volume or mass of the gaseous fuel or

feedstock used in month n (scf (at standard 

conditions of 68 °F and atmospheric pressure)

or kg of fuel or feedstock).

CCn = Average carbon content of the gaseous fuel or

feedstock for month n (kg carbon per kg of 

fuel or feedstock). MWn = Average 

molecular weight of the gaseous fuel or

feedstock for month n (kg/kg-mole). If you 

measure mass, the term “MWn/MVC” is replaced 

with “1”.

MVC = Molar volume conversion factor (849.5 scf per 

kg-mole at standard conditions).

k = Months in the year.

44/12 = Ratio of molecular weights, CO2 to carbon. 

0.001 = Conversion factor from kg to metric 

tons.

(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:
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Where:

CO2 = Annual CO2 emissions arising from fuel and 

feedstock consumption (metric tons/yr).

Fdstkn = Volume or mass of the liquid fuel or feedstock 

used in month n (gallons or kg of fuel or

feedstock).

CCn = Average carbon content of the liquid fuel or

feedstock, for month n (kg carbon per gallon 

or kg of fuel or feedstock).

k = Months in the year.

44/12 = Ratio of molecular weights, CO2 to carbon.

0.001 = Conversion factor from kg to metric tons.

(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:

Where:

CO2 = Annual CO2 emissions from fuel and feedstock 

consumption in metric tons per month (metric 

tons/yr).

Fdstkn = Mass of solid fuel or feedstock used in month 

n (kg of fuel or feedstock).

CCn = Average carbon content of the solid fuel or

feedstock, for month n (kg carbon per kg of 

fuel or feedstock).

k = Months in the year.

44/12 = Ratio of molecular weights, CO2 to carbon.

0.001 = Conversion factor from kg to metric tons.

(c) If GHG emissions from a hydrogen production process 

unit are vented through the same stack as any combustion unit or 
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process equipment that reports CO2 emissions using a CEMS that 

complies with the Tier 4 Calculation Methodology in subpart C of 

this part (General Stationary Fuel Combustion Sources), then the 

calculation methodology in paragraph (b) of this section shall 

not be used to calculate process emissions. 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 (General Stationary Fuel Combustion 

Sources).

§ 98.164 Monitoring and QA/QC requirements.

The GHG emissions data for hydrogen production process 

units must be quality-assured as specified in paragraphs (a) or 

(b) of this section, as appropriate for each process unit:

(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 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 
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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). 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.

(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).

(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).

(5) 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, 
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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).
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(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).
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(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).

§ 98.165 Procedures for estimating missing data.

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.
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(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.

§ 98.166 Data reporting requirements.

In addition to the information required by §98.3(c), each 

annual report must contain the information specified in 

paragraphs (a) or (b) of this section, as appropriate, and 

paragraphs (c) and (d) of this section:

(a) If a CEMS is used to measure CO2 emissions, then you 

must report the relevant information required under §98.36 for 

the Tier 4 Calculation Methodology and the following information 

in this paragraph (a):

(1) Unit identification number and annual CO2 emissions.
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(2) Annual quantity of hydrogen produced (metric tons) for 

each process unit.

(3) Annual quantity of ammonia produced (metric tons), if 

applicable, for each process unit.

(b) If a CEMS is not used to measure CO2 emissions, then you 

must report the following information for each hydrogen 

production process unit:

(1) Unit identification number and annual CO2 emissions.

(2) Monthly consumption of each fuel and feedstock used for 

hydrogen production and its type (scf or kg of gaseous fuels and 

feedstocks, gallons or kg of liquid fuels and feedstocks, kg of 

solid fuels and feedstocks).

(3) Annual quantity of hydrogen produced (metric tons).

(4) Annual quantity of ammonia produced, if applicable 

(metric tons).

(5) Monthly analyses of carbon content for each fuel and 

feedstock used in hydrogen production (kg carbon/kg of gaseous 

and solid fuels and feedstocks, kg carbon per gallon or kg of

liquid fuels and feedstocks).

(6) Monthly analyses of the molecular weight of gaseous 

fuels and feedstocks (kg/kg-mole) used, if any.

(c) Quantity of CO2 collected and transferred off site in 

either gas, liquid, or solid forms, following the requirements 

of subpart PP of this part.
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(d) Annual quantity of carbon other than CO2 collected and 

transferred off site in either gas, liquid, or solid forms (kg 

carbon).

§ 98.167 Records that must be retained.

In addition to the information required by §98.3(g), you 

must retain the records specified in paragraphs (a) through (b) 

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.

(b) If a CEMS is not used to measure CO2 emissions, then you 

must retain records of all analyses and calculations conducted 

as listed in §§98.166(b), (c), and (d).

(c) For units using the calculation methodologies described 

in §98.163(b), the records required under §98.3(g) must include 

both the company records and a detailed explanation of how 

company records are used to estimate the following:

(1) Fuel and feedstock consumption, when solid fuel and 

feedstock is combusted and a CEMS is not used to measure GHG 

emissions. 

(2) Fossil fuel consumption, when, pursuant to §98.33(e), 

the owner or operator of a unit that uses CEMS to quantify CO2

emissions and that combusts both fossil and biogenic fuels 
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separately reports the biogenic portion of the total annual CO2

emissions. 

(3) Sorbent usage, if the methodology in §98.33(d) is used 

to calculate CO2 emissions from sorbent.

(d) The owner or operator must document the procedures used 

to ensure the accuracy of the estimates of fuel and feedstock 

usage and sorbent usage (as applicable) 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.

§ 98.168 Definitions.

All terms used in this subpart have the same meaning given 

in the Clean Air Act and subpart A of this part.