ISO/DIS 19870-1:2025(en)

ISO/TC 197/SC 1

Secretariat: SCC

Date: 2025-03-10

Hydrogen technologies — Methodology for determining the greenhouse gas emissions associated with the hydrogen supply chain - Part 1: Emissions associated with the production of hydrogen to production gate

© ISO 2025

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Contents

Foreword

ISO (the International Organization for Standardization) is a worldwide federation of national standards bodies (ISO member bodies). The work of preparing International Standards is normally carried out through ISO technical committees. Each member body interested in a subject for which a technical committee has been established has the right to be represented on that committee. International organizations, governmental and non-governmental, in liaison with ISO, also take part in the work. ISO collaborates closely with the International Electrotechnical Commission (IEC) on all matters of electrotechnical standardization.

The procedures used to develop this document and those intended for its further maintenance are described in the ISO/IEC Directives, Part 1. In particular, the different approval criteria needed for the different types of ISO document should be noted. This document was drafted in accordance with the editorial rules of the ISO/IEC Directives, Part 2 (see www.iso.org/directives).

ISO draws attention to the possibility that the implementation of this document may involve the use of (a) patent(s). ISO takes no position concerning the evidence, validity or applicability of any claimed patent rights in respect thereof. As of the date of publication of this document, ISO had not received notice of (a) patent(s) which may be required to implement this document. However, implementers are cautioned that this may not represent the latest information, which may be obtained from the patent database available at www.iso.org/patents. ISO shall not be held responsible for identifying any or all such patent rights.

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This document was prepared by Technical Committee ISO/TC 197, Hydrogen technologies, Subcommittee SC 1, Hydrogen at scale and horizontal energy systems.

Any feedback or questions on this document should be directed to the user’s national standards body. A complete listing of these bodies can be found at www.iso.org/members.html.

Introduction

The Paris Agreement was adopted at the UN Climate Change conference (COP21) with the aims of: strengthening the global response to the threat of climate change, restricting global temperature rise to below 2 °C above pre-industrial levels and pursuing efforts to limit the temperature increase to 1,5 °C above pre-industrial levels. To meet these goals, greenhouse gas (GHG) emissions need to be reduced by about 45 % from 2010 levels by 2030, reaching net zero in 2050 (IPCC, 2018; UNFCCC, 2021).

GHG initiatives on mitigation rely on the quantification, monitoring, reporting and verification of GHG emissions and/or removals. International Standards that support the transformation of scientific knowledge into tools can help in reaching the targets of the Paris Agreement to address climate change.

ISO 14044 defines the requirements and guidelines identified in existing International Standards on life cycle assessment (LCA). The ISO 14060 series provides clarity and consistency for quantifying, monitoring, reporting and validating or verifying GHG emissions and removals to support sustainable development through a low-carbon economy. It also benefits organizations, project proponents and stakeholders worldwide by providing clarity and consistency on quantifying, monitoring, reporting and validating or verifying GHG emissions and removals.

ISO 14067 is based on the requirements and guidelines on LCA identified in ISO 14044 and aims to set specific requirements for the quantification of a carbon footprint (CFP) and a partial CFP. ISO 14067 defines the principles, requirements and guidelines for the quantification of the carbon footprint of products. Its aim is to quantify GHG emissions associated with the lifecycle stages of a product, beginning with resource extraction and raw material sourcing and extending through the production, use and end-of-life stages of the product.

Figure 1 illustrates the relationship between ISO 14067 and other ISO documents on LCA.

Figure 1 — Relationship between standards beyond the GHG management family of standards (source ISO 14067:2018)

Hydrogen can be produced from diverse sources including renewables, nuclear and fossil fuels, with or without carbon capture, utilization and storage (CCUS). Hydrogen can be used to decarbonize numerous sectors.

A particular challenge is that identical hydrogen molecules can be produced and combined from sources that have different GHG intensities. Similarly, hydrogen-based fuels and derivatives will be indistinguishable and can be produced from hydrogen combined with a range of fossil and low-carbon inputs. Indeed, some of the products made from hydrogen (e.g. electricity) can themselves be used in the production of hydrogen. Accounting standards for different sources of hydrogen along the supply chain (see Figure 2) will be fundamental to create a market for low-carbon hydrogen, and these standards need to be agreed upon internationally. Additionally, there is the possibility that consumption gates are not located in proximity to hydrogen production gates, requiring hydrogen transport. ISO 14083 gives guidelines for the quantification and reporting of GHG emissions arising from transport chain operations.

A mutually recognized international framework that is robust, and that avoids miscounting or double counting of environmental impacts is needed. Such a framework will provide a mutually agreed upon approach to “guarantees" or “certificates” of origin, and will cover greenhouse gas inputs used for hydrogen production, conditioning, conversion and transport.

The series of international standards ISO 19870 aims at establishing methodologies that should be applied, in line with ISO 14067, to the specific case of the hydrogen value chain, covering different production processes and other parts of the value chain, such as conditioning hydrogen in different physical states, conversion of hydrogen into different hydrogen carriers and the subsequent transport up to the consumption gate. This document, ISO 19870-1 considers the steps up to the production gate.

Figure 2 — Examples of hydrogen supply chain

Hydrogen technologies – Methodology for determining the greenhouse gas emissions associated with the hydrogen supply chain - Part 1: Emissions associated with the production of hydrogen to production gate

ISO 14044 requires the goal and scope of an LCA to be clearly defined and be consistent with the intended application. Due to the iterative nature of LCAs, it is possible that the LCA scope needs to be refined during the study.

The goals and scopes of the methodologies correspond to either approach a) or b), given below, that ISO 14040:2006, Annex A2 gives as two possible approaches to LCAs.

a) An approach that assigns elementary flows and potential environmental impacts to a specific product system, typically as an account of the history of the product. See Section 4.1.2.

b) An approach that studies the environmental consequences of possible (future) changes between alternative product systems. See Section 4.1.3.

In this document, approach (a) is referred to as an attributional approach, while approach (b) is referred to as a consequential approach. Complementary information is accessible in the ILCD handbook^[1].

A Carbon Footprint of a Product (3.1.2) or Partial Carbon Footprint of a Product (3.1.3) as defined by ISO 14067 may be estimated using either the attributional or the consequential approach, the latter corresponding to the use of “system expansion via substitution” to avoid allocation when a unit process yields multiple co-products. This document applies to the CFP for hydrogen production.

There are numerous pathways to produce hydrogen. This document describes in the annexes the requirements and evaluation methods applied to several hydrogen production pathways of interest.

This document considers the GHG emissions associated with hydrogen production up to the production gate. This document applies to and includes every steps within the production process up to the production gate (see Figure 2 in the Introduction).

Complementary documents in the ISO 19870-X series will consider hydrogen conditioning, conversion and transport methods.

The following documents are referred to in the text in such a way that some or all of their content constitutes requirements of this document. For dated references, only the edition cited applies. For undated references, the latest edition of the referenced document (including any amendments) applies.

ISO 14040:2006, Environmental management — Life cycle assessment — Principles and framework

ISO 14044, Environmental management — Life cycle assessment — Requirements and guidelines

ISO 14067:2018, Greenhouse gases — Carbon footprint of products — Requirements and guidelines for quantification

ISO 14083:2023, Greenhouse gases — Quantification and reporting of greenhouse gas emissions arising from transport chain operations

ISO/TS 14071, Environmental management — Life cycle assessment — Critical review processes and reviewer competencies: Additional requirements and guidelines to ISO 14044:2006

For the purposes of this document, the following terms and definitions apply.

ISO and IEC maintain terminology databases for use in standardization at the following addresses:

— ISO Online browsing platform: available at https://www.iso.org/obp

— IEC Electropedia: available at https://www.electropedia.org/

3.1.1

allocation

partitioning the input (3.2.8) or output (3.2.10) flows of a process or a product system (3.2.3) between the product system under study and one or more other product systems

[SOURCE: ISO 14040:2006 and ISO 14040:2006/AMD 1:2020]

3.1.2

carbon footprint of a product

CFP

sum of greenhouse gas emissions (3.1.12) and greenhouse gas removals (3.1.4) in a product system (3.2.3), expressed as CO₂ equivalent (3.1.10) and based on a life cycle assessment (3.4.5) using the single impact category of climate change

Note 1 to entry: A CFP can be disaggregated into a set of figures identifying specific GHG emissions (3.1.12) and removals (3.1.4). A CFP can also be disaggregated into the stages of the life cycle (3.4.4).

Note 2 to entry: The results of the quantification of CFP (3.1.8) are documented in the CFP study report expressed in mass of CO₂e (3.1.11) per functional unit (3.2.14).

[SOURCE: ISO 14067:2018, 3.1.1.1]

3.1.3

partial CFP

sum of greenhouse gas emissions (3.1.12) and greenhouse gas removals (3.1.4) of one or more selected process(es) in a product system (3.2.3) expressed as CO₂ equivalents (3.1.10) and based on the selected stages or processes within the life cycle (3.4.4)

Note 1 to entry: A partial CFP is based on or compiled from data related to (a) specific process(es) or footprint information modules (defined in ISO 14026:2017, 3.1.4), which is (are) part of a product system (3.2.3) and can form the basis for quantification of a carbon footprint of a product (CFP). More detailed information on information modules is given in ISO 14025:2006, 5.4.

Note 2 to entry: The results of the quantification of the partial CFP are documented in the CFP study report expressed in mass of CO₂e (3.1.10) per declared unit.

Note 3 to entry: In this document, partial CFP of hydrogen is extends from raw material extraction up to the production gate.

3.1.4

greenhouse gas removal

GHG removal

withdrawal of a greenhouse gas (3.1.9) from the atmosphere

[SOURCE: ISO 14067:2018, 3.1.2.6]

3.1.5

CFP study

all activities that are necessary to quantify and report the carbon footprint of a product (3.1.2) or a partial CFP (3.1.3)

[SOURCE: ISO 14067:2018, 3.1.1.4]

3.1.6

product category

group of products that can fulfil equivalent functions

[SOURCE: ISO 14025:2006, 3.12]

3.1.7

production batch

amount of products produced by a device between any two points in time selected by the operator

3.1.8

quantification of CFP

activities that result in the determination of the carbon footprint of a product (3.1.2) or a partial CFP (3.1.3)

Note 1 to entry: Quantification of the carbon footprint of a product (3.1.2) or the partial CFP (3.1.3) is part of the CFP study (3.1.5)

[SOURCE: ISO 14067:2018, 3.1.1.6]

3.1.9

greenhouse gas

GHG

gaseous constituent of the atmosphere, both natural and anthropogenic, that absorbs and emits radiation at specific wavelengths within the spectrum of infrared radiation emitted by the Earth’s surface, the atmosphere and clouds

Note 1 to entry: For a list of greenhouse gases (3.1.9), see the latest IPCC Assessment Report.

Note 2 to entry: Water vapour and ozone, which are anthropogenic as well as natural greenhouse gases (3.1.9), are not included in the carbon footprint of a product (3.1.2).

Note 3 to entry: The focus of this document is limited to long-lived GHGs and it therefore excludes climate effects due to changes in surface reflectivity (albedo) and short-lived radiative forcing agents (e.g. black carbon and aerosols).

[SOURCE: ISO 14067:2018, 3.1.2.1]

3.1.10

carbon dioxide equivalent

CO₂ equivalent

CO₂e

unit for comparing the radiative forcing of a greenhouse gas (3.1.9) to that of carbon dioxide

Note 1 to entry: Mass of a greenhouse gas is converted into CO₂ equivalents by multiplying the mass of the greenhouse gas (3.1.9) by the corresponding global warming potential (3.1.11) or global temperature change potential (GTP) of that gas.

Note 2 to entry: In the case of GTP, CO₂ equivalent is the unit for comparing the change in global mean surface temperature caused by a greenhouse gas to the temperature change caused by carbon dioxide.

[SOURCE: ISO 14067:2018, 3.1.2.2]

3.1.11

global warming potential

GWP

index, based on radiative properties of greenhouse gases (3.1.9) (GHG) measuring the radiative forcing following a pulse emission of a unit mass of a given GHG in the present-day atmosphere integrated over a chosen time horizon, relative to that of carbon dioxide (CO₂)

Note 1 to entry: “Index” as used in this document is a “characterization factor” as defined in ISO 14040:2006, 3.37.

Note 2 to entry: A “pulse emission” is an emission at one point in time.

[SOURCE: ISO 14067:2018, 3.1.2.4]

3.1.12

greenhouse gas emission

GHG emission

release of a greenhouse gas (3.1.9) into the atmosphere

[SOURCE: ISO 14067:2018, 3.1.2.5]

3.1.13

greenhouse gas emission factor

GHG emission factor

coefficient relating activity data with the greenhouse gas emission (3.1.3)

[SOURCE: ISO 14067:2018, 3.1.2.7]

3.1.14

capital goods emission

CAPEX emission

GHG emissions (3.1.12) related to the manufacturing of capital goods

3.1.15

subdivision

virtual subdivision

decomposition of a unit process into physically or virtually distinguishable sub-process steps with the possibility to collect data exclusively for those sub-processes

3.1.16

hydrogen

gas mainly composed of hydrogen molecules.

Note 1 to entry: hydrogen molecule is referred as H₂.

3.1.17

physical relationship

relation between co-products (3.2.4) based on a chosen physical characteristic (e.g., mass, energy content, volume). A physical relationship can be used (1) to allocate input flows to co-products (3.2.4) based on the specific function the inputs perform in relation to the individual co-products (3.2.4) and/or (2) to allocate GHG emissions (3.1.12) to the individual co-products (3.2.4)

3.2.1

product

any goods or service

Note 1 to entry: The product can be categorized as follows:

— services (e.g. transport);

— software (e.g. computer program, dictionary);

— hardware (e.g. engine mechanical part);

— processed materials (e.g. lubricant).

[SOURCE: ISO 14040:2006, 3.9]

3.2.2

product flow

products (3.2.1) entering from or leaving to another product system (3.2.3)

[SOURCE: ISO 14040:2006, 3.27]

3.2.3

product system

collection of unit processes with elementary flows (3.2.16) and product flows (3.2.2), performing one or more defined functions and which models the life cycle (3.4.4) of a product (3.2.1)

[SOURCE: ISO 14044:2006, 3.28]

3.2.4

co-product

one of two or more products (3.2.1) coming from the same unit process or product system (3.2.3) that is not considered waste (3.3.15)

[SOURCE: modified from ISO 14040:2006, 3.10]

3.2.5

conditioning

means changing the physical conditions (e.g. temperature, pressure) of hydrogen for the purpose of its storage or transport

Note 1 to entry: In this document, examples are changing the pressure of gaseous hydrogen or liquefying gaseous hydrogen.

3.2.6

conversion

means changing the chemical conditions of a chemical species

3.2.7

heating value

amount of energy released when a fuel is burned completely

Note 1 to entry: Care must be taken not to confuse higher heating values (HHVs) and lower heating values (LHVs).

3.2.8

input

product (3.2.1), material or energy flow (3.2.17) that enters a unit process

Note 1 to entry: Products (3.2.1) and materials include raw materials, intermediate products (3.2.9) and co-products (3.2.4).

[SOURCE: ISO 14040:2006, 3.21]

3.2.9

intermediate product

output from a unit process that is input to other unit processes that requires further transformation within the system

[SOURCE: ISO 14040:2006, 3.23]

3.2.10

output

product (3.2.1), material or energy flow (3.2.17) that leaves a unit process (3.2.13)

Note 1 to entry: Products (3.2.1), and materials include raw materials, intermediate products (3.2.9), co-products (3.2.4) and releases (3.4.11).

[SOURCE: ISO 14040:2006, 3.25]

3.2.11

system boundary

boundary based on a set of criteria representing which unit processes (3.2.13) are a part of the system under study

[SOURCE: ISO 14040:2006/AMD 1:2020, 3.32]

3.2.12

system expansion

concept of expanding the product system (3.2.3) to include additional functions related to the co-products (3.2.4)

Note 1 to entry: The product system (3.2.3) that is substituted by the co-product (3.2.4) is integrated in the product system (3.2.3) under study. In practice, the co-products (3.2.4) are compared to other substitutable products, and the environmental burdens associated with the substituted product(s) are subtracted from the product system (3.2.3) under study. The identification of this substituted system is done in the same way as the identification of the upstream system for intermediate product (3.2.9) inputs (3.2.8). See also ISO/TR 14049:2012, 6.4

Note 2 to entry: The application of system expansion (3.2.12) involves an understanding of the market for the co-products (3.2.4). Decisions about system expansion (3.2.12) can be improved through understanding the way co-products (3.2.4) compete with other products, as well as the effects of any product substitution upon production practices in the industries impacted by the co-products (3.2.4).

Note 3 to entry: Can be referred to as system expansion (3.2.12) and also as expanding the system boundary (3.2.11).

[SOURCE: ISO 14044:2006/AMD 2:2020, D.2.1]

3.2.13

process

set of interrelated or interacting activities that transforms inputs (3.2.8) into outputs (3.2.10)

[SOURCE: ISO 14044:2006, 3.11]

3.2.14

functional unit

quantified performance of a product system (3.2.3) for use as a reference unit

Note 1 to entry: As the carbon footprint of a product treats information on a product basis, an additional calculation based on a declared unit can be presented.

[SOURCE: ISO 14040:2006, 3.20]

3.2.15

elementary flow

material or energy entering the system being studied that has been drawn from the environment without previous human transformation, or material or energy leaving the system being studied that is released into the environment without subsequent human transformation

Note 1 to entry: “Environment” is defined in ISO 14001:2015, 3.2.1.

[SOURCE: ISO 14044:2006, 3.12]

3.2.16

energy flow

input (3.2.8) to or output (3.2.10) from a unit process or product system (3.2.3), quantified in energy units

Note 1 to entry: Energy flow that is an input can be called an energy input; energy flow that is an output can be called an energy output.

[SOURCE: ISO 14040:2006, 3.13]

3.2.17

feedstock

any material input to the hydrogen plant that is not generated at the hydrogen plant itself. A non-exhaustive list may include

— Natural gas (e.g. for steam methane reforming)

— Biomethane/Renewable Natural Gas^[1] (e.g. for steam methane reforming)

—

— Biomass

— Coal (e.g. for gasification)

— Liquid Hydrocarbons (e.g. for catalytic reforming of naphtha)

— Biogenic Waste (e.g. for gasification)

— Non-biogenic Waste (e.g. for gasification)

— Oxygen (e.g. for autothermal reforming)

— Water (e.g. for water electrolysis)

— Steam

If a hydrogen plant both generates and utilizes a material (e.g. steam), only the portion that is received by the hydrogen plant from an external source is considered to be a feedstock. For example, steam generated within the hydrogen plant system boundary for use at the hydrogen plant is not considered to be a feedstock.

3.2.18

production gate

location of the end-outlet of the metered product (3.2.1) that leaves the product’s production system boundary

3.2.19

delivery gate

any location where the product (3.2.1) is transferred from one operator to another

3.2.20

consumption gate

location of the final delivery of the product (3.2.1) to its end-use

3.3.1

cut-off criteria

specification of the amount of material or energy flow (3.2.17) or the level of significance of greenhouse gas emissions (3.1.12) associated with unit processes or the product system (3.2.3) to be excluded from a CFP study (3.1.5)

[SOURCE: modified from ISO 14067:2018, 3.1.4.1]

3.3.2

evaluation

element within the life cycle interpretation phase intended to establish confidence in the results of the life cycle assessment (3.3.5)

Note 1 to entry: Evaluation includes completeness check, sensitivity check, consistency check, and any other validation that may be required according to the goal and scope definition of the study

[SOURCE: ISO 14040:2006]

3.3.3

fugitive emissions

emissions that are not physically controlled but result from the intentional or unintentional releases (3.3.10) of GHGs (3.1.9)

Note 1 to entry: They commonly arise from the production, processing, transmission, storage, and use of fuels and other chemicals, often through joints, seals, packing, gaskets, etc.

[SOURCE: 2004 GHG protocol, Chapter 4.6]

3.3.4

life cycle

consecutive and interlinked stages related to a product (3.2.1), from raw material acquisition or generation from natural resources to end-of-life treatment

Note 1 to entry: “Raw material” is defined in ISO 14040:2006, 3.15.

Note 2 to entry: Stages of a life cycle related to a product include raw material acquisition, production, distribution, use and end-of-life treatment.

[SOURCE: ISO 14067:2018, 3.1.4.2]

3.3.5

life cycle assessment

LCA

compilation and evaluation of the inputs (3.2.8), outputs (3.2.10) and the potential environmental impacts of a product (3.2.1) throughout its life cycle (3.3.4)

Note 1 to entry: “Environmental impact” is defined in ISO 14001:2015, 3.2.4.

[SOURCE: modified from ISO 14067:2018, 3.1.4.3]

3.3.6

life cycle inventory analysis

LCI

phase of life cycle assessment (3.3.5) involving the compilation and quantification of inputs (3.2.8) and outputs (3.2.10) for a product throughout its life cycle (3.3.4)

[SOURCE: ISO 14044:2006, 3.3]

3.3.7

location-based method

uses the average emissions intensity of networks supplying energy commodities for consumption, such as electricity, using mostly grid-average emission factors in the location in which energy consumption occurs.

[SOURCE: modified from ISO 14064-1:2018, Annex E]

3.3.8

market-based method

a method to assign the attributes of the product (3.2.1) produced by a specific producer to the product (3.2.1) consumed by or delivered to a specific user while the product (3.2.1) is physically distributed through a common infrastructure.

Note 1 to entry: These choices (purchasing energy certificates or differentiated electricity product) may be reflected through contractual arrangements between the user and the producer.

3.3.9

process emissions

direct emissions within the system boundary, including emissions associated with waste treatment and disposal, such as, but not limited to, chemical conversions and combustion of solid, liquid and/or gaseous fuels or feedstock’s

3.3.10

releases

emissions to air and discharges to water and soil

[SOURCE: ISO 14040:2006, 3.30]

3.3.11

sensitivity analysis

systematic procedures for estimating the effects of the choices made regarding methods and data on the outcome of a CFP study (3.1.5)

[SOURCE: ISO 14067:2018, 3.1.4.7]

3.3.12

sensitivity check

process to determine whether the information obtained from a sensitivity analysis (3.3.11) is relevant for reaching the conclusions and for giving recommendations

[SOURCE: ISO 14040:2006/AMD1:2020, 3.43]

3.3.13

transparency

open, comprehensive and understandable presentation of information

[SOURCE: ISO 14040:2006, 3.7]

3.3.14

uncertainty analysis

systematic procedure to quantify the uncertainty introduced in the results of a life cycle inventory analysis (3.3.6) due to the cumulative effects of model imprecision, input uncertainty and data variability

Note 1 to entry: Either ranges or probability distributions are used to determine uncertainty in the results.

[SOURCE: ISO 14040:2006, 3.33]

3.3.15

waste

substances or objects that the holder intends or is required to dispose of

Note 1 to entry: This definition is taken from the Basel Convention on the Control of Transboundary Movements of Hazardous Wastes and Their Disposal (22 March 1989), but is not confined in this document to hazardous waste.

[SOURCE: ISO 14040:2006, 3.35]

Note 2 to entry: Wastes potentially used as feedstocks for hydrogen production vary widely in composition and by region. In this document, “waste” is defined as substances or objects that the holder intends or is required to dispose of and that can be used as a feedstock for hydrogen production.

“Waste” is not necessarily a permanent designation for a material. If additional valorized product streams were to emerge for a given type of material currently deemed a waste, then competition for its use as a feedstock for hydrogen production might result in upstream emissions impacts.

To determine whether a feedstock is a waste, stakeholders should rely on analysis specific to the country the feedstock was sourced from. Such analysis should account for the quantity of the respective feedstock that is available in the host country, the approximate size of other markets for that feedstock, and the quantity of the feedstock expected to be used for hydrogen production to determine whether valorization of the waste would have occurred otherwise.

3.3.16

biogenic waste

the biogenic portion of waste (3.3.15)

Note 1 to entry: A non-exhaustive list may include:

— The biogenic portion of municipal solid waste (MSW),

— Animal waste,

— Sewage sludge,

— Food industry residues,

— Agricultural residues,

— Food and agricultural waste (e.g., home food waste collection)

— Forests that would traditionally be left to decompose naturally (ICAO, 2019).

Whether a product (3.2.1) is considered a waste (3.3.15) or a valorized product (3.2.1) is based on the properties of the material (e.g., corn stover versus corn kernel). A tree intended for timber harvest may be thinned because of some perceived defect (e.g., a curved trunk, or relatively diminutive size relative to other trees in the stand). The valorization of the “waste” material which could be considered “slash and thinning” may change the decision-making of the forester regarding the disposition of woody material.

Ultimately, biomass suppliers should provide hydrogen producers with information establishing whether biomass received as a feedstock (3.2.17) for hydrogen production is intentionally-produced biomass or biogenic waste. A country’s legislations may encompass this definition.

3.3.17

non-biogenic waste

the non-biogenic portion of waste (3.3.15)

Note 1 to entry: Non-biogenic waste includes content of fossil origin which is not suitable for material recovery. A non-exhaustive list may include:

— The non-biogenic portion of Municipal Solid Waste (MSW)

— The non-biogenic portion of Industrial Waste

— Plastic waste (3.3.15) of fossil origin (in some jurisdictions (e.g. Japan), this stream is considered to be a part of MSW)

3.4.1

organization

person or group of people that has its own functions with responsibilities, authorities and relationships to achieve its objectives

Note 1 to entry: The concept of organization includes, but is not limited to, sole-trader, company, corporation, firm, enterprise, authority, partnership, charity or institution, or part or combination thereof, whether incorporated or not, public or private.

[SOURCE: ISO 14001:2015, Clause 4]

3.5.1

data quality

characteristics of data that relate to their ability to satisfy stated requirements

[SOURCE: ISO 14040:2006]

3.5.2

double counting

two or more reporting entities take ownership of the same greenhouse gas emissions (3.1.2) or emission reductions

3.5.3

primary data

quantified value of a process (3.2.13) or an activity obtained from a direct measurement or a calculation based on direct measurements

Note 1 to entry: Primary data need not necessarily originate from the product system (3.2.3) under study because primary data might relate to a different but comparable product system (3.2.3) to that being studied.

Note 2 to entry: Primary data can include greenhouse gas emission factors (3.1.3) and/or greenhouse gas activity data (defined in ISO 14064-1:2006, 2.11).

[SOURCE: ISO 14067:2018, 3.1.6.1]

3.5.4

secondary data

data which do not fulfil the requirements for primary data (3.5.3)

Note 1 to entry: Secondary data can include data from databases and published literature, default emission factors from national inventories, calculated data, estimates or other representative data, validated by competent authorities.

Note 2 to entry: Secondary data can include data obtained from proxy processes or estimates.

[SOURCE: ISO 14067:2018, 3.1.6.3]

3.5.5

site-specific data

primary data (3.5.3) obtained within the product system (3.2.3)

Note 1 to entry: All site-specific data are primary data (3.5.3) but not all primary data (3.5.3) are site-specific data because they may be obtained from a different product system (3.2.3).

Note 2 to entry: Site-specific data include greenhouse gas emissions (3.1.12) from GHG sources as well as permanent GHG removals by GHG sinks for one specific unit process within a site.

[SOURCE: ISO 14067:2018, 3.1.6.2]

3.5.6

uncertainty

parameter associated with the result of quantification that characterizes the dispersion of the values that could be reasonably attributed to the quantified amount

Note 1 to entry: Uncertainty can include, for example:

— parameter uncertainty, e.g. greenhouse gas emission (3.1.12) factors, activity data;

— scenario uncertainty, e.g. use stage scenario, end-of-life stage scenario;

— model uncertainty.

Note 2 to entry: Uncertainty information typically specifies quantitative estimates of the likely dispersion of values and a qualitative description of the likely causes of the dispersion.

[SOURCE: ISO 14067:2018, 3.1.6.4]

The proposed emissions accounting methodology aims to be applicable to all hydrogen production pathways, in accordance with ISO 14040, ISO 14044, ISO 14067, ISO 14083, and using guidelines from the GHG protocols and ILCD Handbook which are based on the same ISO standards.

Therefore, referring to ISO 14067, the following criteria shall be applied for the goal and scope definition phase:

a) the product category definition and description of the investigated pathways are identical;

b) the declared unit is identical;

c) the system boundary is equivalent: from raw material extraction to production gate;

d) the description of data is equivalent;

e) the criteria for inclusion of inputs and outputs are equivalent;

f) the data quality requirements (e.g. transparency, coverage, precision, completeness, representativeness, consistency and reproducibility) are as consistent as technically feasible;

g) specific GHG emissions and captures are treated identically;

h) the units (described in Annexes) are identical.

The following criteria shall be applied for the life cycle inventory:

i) the methods of data collection and data quality requirements are equivalent when technically feasible;

j) the calculation procedures are identical;

k) the allocation of the flows is consistent;

l) the applied GWPs are identical.

The calculation method for the CFP of hydrogen can differ depending upon the intended use of the result of the evaluation. The present document describes two main situations according to ISO 14040:2006, Annex A.2. A general recommended approach is also provided in each annex. For different approaches, a justification has to be provided following a sensitivity analysis.

An attributional approach estimates the GHG emissions occurring within the value chain of the production of hydrogen. The estimation of emissions is performed for each activity from raw material extraction to production gate, within the value chain, without considering emissions or benefits outside the scope of the analysed system. Such a case also refers to situation C2 described in the ILCD handbook.

A consequential approach includes GHG emissions within the product system boundary, and considers possible GHG emissions that occur outside the boundaries of the product system. In this document, for a CFP, a consequential approach may be employed in the limited way corresponding to the use of “system expansion via substitution” to avoid allocation when a unit process yields multiple co-products. These co-products may displace alternatives methods of production.

Requirements for applying system expansion via substitution includes:

— The activities to be considered and the corresponding lifecycle stages for these activities shall be clearly stated in the goal and scope of the analysis.

— The counterfactual scenario according to which the consequence is evaluated shall be clearly stated in the goal and scope of the analysis.

A consequential approach may also be used for a broader impact assessment to include:

(1) specific upstream consequences of the production,

(2) downstream consequences of the usage of the product, or

(3) macro-economic consequences of the hydrogen production.

In all these cases, the GHG inventory is expanded beyond the boundaries of the hydrogen value chain from the raw material extraction to the production gate, considering emissions or benefits outside the boundaries of the product system. Such cases also refer to situation C1 described in the ILCD handbook. The choice of consequential approach and associated system boundaries will be defined by the goal of the analysis. These broader impacts may be considered in addition to the CFP of the product but may not be part of it within the ISO 14067 definition of CFP.

Such applications are included in Annex B - Consequential Approach Examples for Hydrogen Production.

General Principles

The “raw material extraction-to -consumption gate” system boundary is divided in three sections considering the hydrogen i) production, ii) conditioning/conversion and iii) transport, as described in Figure 3.

Analysis methods described in the current document cover a “raw material extraction-to-production gate” system boundary, including direct and indirect emissions and excluding emissions deemed insignificant per 4.2.2. Hydrogen production CFP shall not include carbon offsetting (See ISO 14067, clause 6.3.4.1.).

Indirect emissions considered include associated impacts from the upstream activities of raw material acquisition phase, raw material transport phase, and downstream activities for discharge/disposal of waste, etc. GHG contributions are defined in terms of carbon dioxide equivalent (CO₂e).

Figure 3 — Schematic of “raw material extraction to production gate” system boundary adopted for this document

The emissions from the construction, manufacturing, replacements and upgrades, and decommissioning of the capital goods (including hydrogen production device, etc.), business travel, employee commuting and upstream leased assets are not considered as normative in the raw material extraction to the production gate system boundary. The rationale for this simplification was motivated by the comparatively small contribution that these emissions add to emissions associated with fossil pathways.^[2] However, in some cases these emissions may be substantial (e.g. in the case of electrolytic hydrogen using certain types of electricity from renewable sources). Therefore, the quantification of these capital goods emissions, also known as “CAPEX emissions", shall be provided for information separately following relevant ISO documents (e.g., ISO 14044).

The functional unit for CFP analysis of hydrogen production is established as 1 kg of hydrogen at a pressure and a purity that corresponds to the inlet requirements of the subsequent stage. As such, any leakages in the production of hydrogen will be accounted for in the functional unit. For hydrogen purity lower than 99,9 mol%, refer to Annex A. The downstream boundary limit is the production gate (3.2.23).

The reporting metric for carbon foot printing shall be kgCO₂e/kg_hydrogen^[2] for hydrogen at the production gate.

Hydrogen production

There are many pathways for hydrogen production, with many different processes and technologies being proposed and implemented. This document provides details for hydrogen purity in Annex A, feedstock treatment for hydrogen production in Annex C and details for specific production pathways in Annexes D to L.

Emissions associated with hydrogen infrastructure past the hydrogen production gate (e.g. liquefaction, hydrogenation in a carrier) are not considered in this document but will be addressed in the ISO 19870-X series.

In general, efforts shall be taken to include all processes and flows that are attributable to the analysed system. Completeness based on environmental significance should be tested by including and excluding processes in the hydrogen production system boundary, from raw material extraction to the production gate, to determine if results change^[3]. The cut-off criteria used to exclude certain processes and flows of minor importance shall be clearly and consistently defined within the goal and scope definition phase, and, in total, shall be below 0,05 kgCO₂e/ kg_hydrogen.

The final sensitivity analysis of the inputs and outputs data shall include the mass, energy and environmental significance criteria (expressed in kgCO₂e/ kg_hydrogen) and all inputs not considered in the study shall be reported. For more information, see ISO 14044:2006+A2, section 4.2.3.3.3.

General Principles

The CFP of produced hydrogen selects climate change as the environmental impact category. The characteristic factors are shown in Table 1.

Table 1 — Environmental impact category, characterization model and unit

The main GHGs considered in this document are carbon dioxide (CO₂), methane (CH₄) and nitrous oxide (N₂O).

The global warming potential (GWP) for a 100-year period of the various greenhouse gases is expressed in kilograms of CO₂e. GWP for other time horizons and GTP, as given by the Intergovernmental Panel on Climate Change (IPCC), may be used for information in addition to GWP 100, but should be reported separately.

This document applies the latest IPCC Assessment Report recognized by the United Nations. IPCC has released updated values in AR6 WG1^[8] documents but AR5 WG1 ^[6] values are still the values recognised by the United Nations. The other GHGs mentioned by IPCC (AR5 WG1:2013, Appendix 8.A)^[6] shall be included in the estimation of the CFP.

Table 2 — shows the GWP for a period of 100 years of the main GHGs according to the Fifth Assessment Reports of the IPCC^[7].

Table 2 — Global warming potential (GWP) of selected GHGs [IPCC 2013]

Applying the GWP 100 coefficients in the IPCC Assessment Reports, the GHG emissions in kgCO₂e can be calculated by:

(1)

Where [CO₂e], P_i and Q_i are, respectively, kilograms of CO₂e, kilograms of a species (i) and coefficient of a species in gCO₂e/g species (i).

The emissions from the construction, manufacturing, replacements and upgrades, and decommissioning of the capital goods (including hydrogen production device, etc.), are only considered to inform separately on the capital goods emissions. Furthermore, energy requirements and emissions resulting from the manufacturing and decommissioning of installations or applications (e.g. vehicles) consuming the hydrogen are not considered.

The hydrogen considered should be evaluated for hydrogen produced in an industrial plant as the object.

The evaluation cycle constrains emissions data collection to the specified time period of hydrogen production for which the CFP is representative. The time period for which the GHG emissions are representative shall be specified and justified.

The time period of GHG emissions and captures relative to the year of production of the product shall be specified in the CFP inventory. The effect of any time difference between when GHG emissions and captures from the product system (as CO₂e) and the year of production, if calculated, shall be documented separately in the CFP study report. The method used to calculate the effect of time difference shall be stated and justified in the CFP study report. The choice of the time period for data collection should consider intra- and inter-annual variability and, when possible, use values representing the trend over the selected period. Where the GHG emissions and captures associated with specific unit processes within the CFP of a product vary over time, data shall be collected over a time period appropriate to establish the average GHG emissions and captures associated with the CFP of the product.

The process, methods and requirements of hydrogen production CFP quantification refer to ISO 14067:2018, Clause 5.

A description of the following items is given for each stage of the CFP of a hydrogen production pathway.

As a minimum, a) to m) shall be provided for each of the CFP of the hydrogen production stage:

a) hydrogen process overview and description: production;

b) emissions accounting method;

c) emissions inventory;

d) energy supply;

e) upstream emissions relating to the upstream extraction of resources, when existing;

f) emissions allocation;

g) results of sensitivity analyses and uncertainty analysis;

h) results of the life cycle interpretation, including conclusions and limitations;

i) disclosure and justification of value choices that have been made in the context of decisions within the study;

j) description of the stages of the life cycle, including a description of the selected use profiles when applicable;

k) assessment of influence of alternative use profiles on the final results;

l) time period for which the carbon footprint is representative;

m) references used in the study.

The methodology should reduce bias and uncertainty by using the highest quality data available. Data quality shall be characterized by both quantitative and qualitative aspects including.

— time-related coverage: age of data and the minimum length of time over which data should be collected;

— geographical coverage: geographical area from which data for unit processes should be collected to satisfy the goal of the carbon footprint study;

— technology coverage: specific technology or technology mix;

— precision: measure of the variability of each data value expressed (e.g. variance);

— Accuracy referring to a qualitative assessment of the discrepancy between a measurement and the actual value

— completeness: percentage of total flow that is measured or estimated;

— representativeness: qualitative assessment of the degree to which the data set reflects the true population of interest (i.e. geographical coverage, time period and technology coverage);

— consistency: qualitative assessment of whether or not the study methodology is applied uniformly to the various components of the sensitivity analysis;

— reproducibility: qualitative assessment of the extent to which information about the methodology and data values would allow an independent practitioner to reproduce the results reported in the carbon footprint study;

— sources of the data;

— uncertainty of the information.

General principles

An overview of the GHG emissions accounting methodology applied to each pathway is summarised below.

Total GHG emissions will be described following Figure 3 as:

(3)

Emissions include all direct and indirect emissions arising in the raw material extraction to production gate system boundary as defined in 4.2.1.

Formula 4 shows the breakdown of the emissions inventory into its components (emissions categories). Individual countries may use additional emissions inventory categories that align with IPCC guidelines.

(4)

measured in kilograms of CO₂e.

Process emissions

Process emissions are direct emissions within the hydrogen production facility, including emissions associated with waste treatment and disposal, such as, but not limited to, chemical conversions and combustion of solid, liquid and/or gaseous fuels or feedstocks including (but not limited to) coal, diesel and natural gas. They also include the GHG emissions of hydrogen that is less than 99,9 mol% pure (refer to Annex A). Process emissions can be estimated via a variety of approaches including use of emission factors and measurement of fuel (volumetric or gravimetric), and direct measurement.

Process emissions should be calculated according to Formula 4:

(5)

where E_process is the sum of GWP-weighted emissions, according to Table 2, released from the process converted into kilograms of CO₂e using Equation 1. This covers combustion of solid, liquid, and gaseous fuels calculated using a variety of methods.

In the case of carbon capture, when applicable:

— for the portion of the captured CO₂ that is sequestered, it shall be considered as waste and the emissions related to capture, processing, transport and sequestration (including monitoring) shall be accounted within the inventory of emissions assigned to the production of hydrogen. To meet the requirements of "stored" CO₂, the CO₂ should be injected into qualified geologic storage facilities (e.g. as qualified by ISO 27914 and ISO 27916).

— for the portion of the captured CO₂ that is utilized, the emissions associated with its capture, processing, transport and storage (including monitoring) are allocated to the utilized CO₂ co-product following Section 4.3.3.

Emissions related to CO₂ utilization shall be accounted for as follows, depending on the goal of the GHG evaluation:

— if the GHG evaluation goal is attributional (see 4.1.2), the GHG emissions resulting from the use of the captured CO₂ shall not be taken into account in the inventory of emissions of the hydrogen production as they do not occur within the life cycle stage of hydrogen production. The fate of the carbon is not accounted for in the CFP of hydrogen in the attributional approach but can be accounted for using a consequential approach.

— if the GHG evaluation goal is consequential (see 4.1.3), the boundaries of the system may be expanded to include other lifecycle stages of carbon where GHG emissions can be affected as a consequence of hydrogen production.

Fugitive emissions

Fugitive emissions are direct fugitive emissions within the hydrogen production facility, including emissions associated with waste treatment and disposal. Examples include but are not limited to, structural and operational losses, such as leaks and accidental losses, venting, purging as well as other losses due to plant operations. As for most hydrogen producers, fossil fuels are provided by a third-party, fugitive emissions associated with its transmission and distribution are considered in the upstream emissions. Double accounting fugitive emissions and process emissions shall be avoided.

Fugitive emissions should be calculated according to Formula 6:

(6)

where E_fugitive is the sum of GWP-weighted structural and operational emissions, released from fugitives of source type (i) within the module measured and converted in kilograms of CO₂e according to Equation 1.

Other emissions

Other emissions refer to the latest IPCC Assessment Report recognized by the United Nations for emissions of specific GHG gases used across several industry activities (e.g. hydrofluorocarbons (HFCs) used in industrial refrigeration and/or cooling systems, and sulphur hexafluoride (SF₆) used in electrical switchgear).

There are a variety of approaches that may be employed to estimate these emissions. Typically, this can be via assumed leakage rates, or changes in stock levels of the relevant substances as measured throughout the relevant production batch period. These items are expected to be minor sources, and estimation should be sufficient in most cases.

Other emissions should be calculated according to Formula 7:

(7)

where E_other is the sum of GWP-weighted emissions of relevant GHG (as applicable) measured and converted to kilograms of CO₂e according to Equation 1.

Energy supply

General principles

There are two methods to estimate the GHG emissions intensity of energy commodities connecting suppliers with consumers: (1) a location-based method and (2) a market-based method.

(1) A location-based method reflects the average emissions intensity of networks supplying energy commodities for consumption, such as electricity, using mostly grid-average emission factors

(2) A market-based method reflects emissions from the supply of energy that companies have purposefully chosen. It derives emission factors from contractual instruments, which include any type of contract between two parties, such as the sale and purchase of electricity, bundled with attributes about the supplied energy, or for unbundled attribute claims. Markets differ as to what contractual instruments are commonly available or used by companies to purchase energy or claim specific attributes about it, but they can include energy attribute certificates (RECs, GOs, etc.), direct contracts (e.g., renewable or low-carbon electricity, bio methane or renewable natural gas)), supplier specific emission rates, and other default emission factors, e.g. representing the untracked or unclaimed electricity and emissions (termed the “residual mix”), if a company does not have other contractual information.

For the location-based emissions accounting approach, energy supply emissions should be calculated according to Formula 8:

(8)

where E_{energy supply,location} is the GWP-weighted emissions, associated with supply of energy (i) (e.g. electricity, heat, steam, fuel) in kilograms of CO₂e according to Equation 1 (calculated in line with the location-based approach).

For the market-based emissions accounting approach, net energy supply emissions should be calculated according to Formula 9:

(9)

where

Treatment of electricity

GHG emissions from electricity used for hydrogen production shall be restricted to direct emissions and indirect emissions (not including capital goods emissions). Emissions shall include extraction and transport of primary energy commodities used to generate electricity, transformation (i.e. electricity generation), and transmission and distribution losses.

The direct GHG emissions of electricity generation from wind, solar photovoltaic, hydropower, may be assumed to be zero. As mentioned in 4.2.1, capital goods emission shall be reported for information.

The GHG emissions associated with the use of electricity shall include GHG emissions arising from the supply of the electricity including:

— the supplied electricity counted at the in gate of the hydrogen-production facility;

— the losses from the electricity generation process and from transmission and distribution.

a) Electricity generation within the boundaries of the hydrogen production facility

When electricity is generated within the facility and consumed to produce hydrogen and no contractual instruments have been sold or brought through a third-party, then the emissions would be any direct and indirect emissions, as applicable, resulting from generating that electricity. Emissions associated with on-site generation shall not be double counted if already included in the process emissions (Section 4.3.2.2).

b) Electricity generation outside the boundaries of the hydrogen production facility

Electricity supplied to the facility shall account for emissions associated with electricity generation, transmission, and distribution consumed by the plant, considering upstream emissions, operational and downstream emissions and all losses in the electricity-generation facility and transmission and distribution losses.If the GHG evaluation goal is attributional (see 4.1.2):

The electricity emissions reporting method proposed is consistent with ISO 14064-1:2018, Annex E. This approach includes dual reporting requirements consisting of a location-based and market-based method.

The following is adapted from ISO 14064-1:2018, Annex E.

Provided that market based contractual instrument and default emission factors (residual mix) meet proper quality criteria (see Section 4.3.1), the market-based method should be used whenever possible in priority to determine the emission factor of electricity used to produce hydrogen. An example of quality criteria for market-based information can be found in the ISO 14064-1:2018, Annex E.

If the GHG evaluation goal is consequential (see 4.1.3):

The system boundary is usually defined by the goal of the LCA. Regardless of whether electricity is purchased on the generic electricity market or from a specific supplier, a consequential approach may consider effects that are expected as a consequence of changes in electricity demand. Consequential approaches for treatment of electricity are of particular relevance for policy making, where there is an interest in the direct and indirect impacts of expanding hydrogen production and an aim to reduce negative (unintended) effects (see Annex B – Consequential Approach Examples for Hydrogen Production, which includes examples of regulations using a consequential approach for estimating GHG emissions associated with electricity).

Treatment of steam

The steam involved in different processes can be (1) a heat input (e.g. to ensure the required temperature within different sub-processes), (2) a feedstock (e.g. high temperature electrolysis or gas reforming), or (3) a co-product (e.g. steam co-produced in SMRs).

When steam is an input to the hydrogen production facility, the emissions assigned to its production and supply shall be allocated to the co-products of the hydrogen production facility, including the hydrogen, as described in 4.3.3 and the relevant annexes for emissions allocations.

Carbon footprint of the steam supplied to the hydrogen production facility shall be estimated according to ISO 14067.

When steam is a co-product, the GHG emissions shall be determined and allocated based on the process outlined in Section 4.3.3.

Treatment of natural gas

Depending on the available data, calculating the emissions factor for the natural gas used, whether as an energy input or feedstock (kgCO₂e / MJ), shall be done according to the following priority order:

1. using an emission factor derived from direct measurements, where applicable and practical, at the source and site-level^[4] of the gas purchased that is verified by an independent, third-party verifier (see 3.5.5 site-specific data); or if not available

2. using a well-documented and, where available basin-specific, emission factor of the regional gas industry based on an independent, third-party, public-funded scientific analysis (for example the analysis aggregated and validated through the UN Environment Programme’s International Methane Emissions Observatory (IMEO)^[5]); or if not available

3. using an emission factor (the system boundary of the data should match that of the gas purchased) provided by a national authority, or data source which is generally used in the country or area where the natural gas production is located, or otherwise globally used LCA data base. The database name and version shall be reported.

The aforementioned emission factor shall include GHG emissions from gas transport to the hydrogen production facility and fugitive emissions. The emission factor for natural gas shall be reported and justified.

For references on calculating GHG emissions at LNG plants and throughout the LNG chain, refer to ISO6338:2023 and ISO/DIS 6338-2.

Treatment of other possible sources of methane, such as biogas, is provided in Annex C on feedstocks.

Upstream Emissions

Upstream emissions (excluding emissions associated from energy supply, Section 4.3.2.5) refer to upstream emissions associated with any input to a system. This can include key inputs such as oxygen gas among others. Additional input streams may be considered on an as required, based on the cut-off criteria per 4.2.1. This can include items such as water used for electrolysis and chemicals used for water treatment.

All GHG emissions associated with water supply for the production of hydrogen shall be captured within the CFP.^[6]

The overall calculation for estimation of upstream emissions is as follows:

(11)

where E_{upstream emissions} is the GWP-weighted, associated with input (i) measured in kilograms of CO₂e according to Equation 1.

Annex C provides additional guidance regarding the estimation of carbon footprints of feedstocks to hydrogen production plants.

Production pathways for hydrogen often result in various wastes, products and co-products.

According to ISO 14067: 2018, 6.4.6.1: the inputs and outputs shall be allocated to every products and co-products according to a clearly stated and justified allocation procedure.

According to ISO 14067:2018, 6.4.6.2: “The CFP study shall include the identification of the processes shared with other product systems and deal with them in accordance with the stepwise procedure presented below.

NOTE Formally, step 1 is not part of the allocation procedure.

a) Step 1: Wherever possible, allocation should be avoided by

1) dividing the unit process to be allocated into two or more sub-processes separately and collecting the input and output data related to these sub-processes, or

2) expanding the product system to include the additional functions related to the co-products.

b) Step 2: Where allocation cannot be avoided, the inputs and outputs of the system should be partitioned between its different products or functions in a way that reflects the underlying physical relationships between them.

c) Step 3: Where physical relationship alone cannot be established or used as the basis for allocation, the inputs should be allocated between the products and the functions in a way that reflects other relationships between them. For example, input and output data might be allocated between co-products in proportion to the economic value of the products.”

In this document the steps of the allocation procedure according to ISO 14067 are differentiated between an attributional and a consequential approach (Table 3).

The specific allocation method depends on the production process and the associated co-products. Refer to the annexes D to L for more detailed guidance on allocation methods.

Table 3 — Allocation procedure for co-products of the hydrogen production pathway according to ISO 14067:20183, 6.4.6.2 as applied in this document for attributional and consequential approach

This document applies the allocation procedure according to ISO 14067:2018, 6.4.6.2 as follows (Table 3):

Step 1.1: Dividing the unit process to be allocated into two or more sub-processes separately and collecting the input and output data related to these sub-processes

Step 1.1 applies to an attributional and a consequential approach. The following steps help determine whether or not multi-functionality is solvable by subdivision:

(1) Investigate whether the analysed unit process contains physically distinguishable sub-processes,

(2) Investigate whether or not it is possible to collect or determine data exclusively for those sub-processes,

(3) Check whether separate sub-processes can be identified and modelled –each only providing one required functional output.

Based on the outcome, one of the following three options should apply:

(1) Subdivision should be performed, if it is possible to collect or determine data exclusively for those sub-processes.

For example, as described in Annex D, a steam reformer co-producing carbon monoxide (CO), hydrogen, and steam may be virtually subdivided as:

— The SMR reactor producing syngas and steam;

— The CO cold box producing CO and hydrogen and having syngas as an input;

— The water gas shift producing hydrogen and having syngas as an input.

(2) Virtual subdivision should be attempted when a process has 2 or more different inputs with the same physical and chemical characteristics coming from different upstream processes and therefore with different carbon footprints. The process may be virtually subdivided to be considered as the juxtaposition of 2 or more separate processes, each representing one of the different inputs of the subdivided process.

For example,

— A PSA purifying two similar hydrogen rich streams may be virtually subdivided in two parts, each of them considered as a separate PSA treating one of the two flows

— An electrolyser partially consuming renewable electricity may be virtually subdivided in two sub-process and considered as the juxtaposition of one electrolyser consuming exclusively the renewable electricity and another one consuming the remaining part.

(3) Neither subdivision nor virtual subdivision can be performed.

Step 1.2: Expanding the product system to include the additional functions related to the co-products

Expanding the product system to include the additional functions related to the co-products only applies to a consequential approach. It is not applicable to an attributional approach. There are two possibilities for how to apply system expansion:

(1) Via changing the functional unit to include hydrogen and other co-products, and

(2) Via substitution by assigning a co-product the same carbon footprint as an alternative product.

System expansion via changing the functional unit to include hydrogen and other co-products is not aligned with this document, which defines the functional unit as 1 kg of hydrogen (See 4.2.1.1 General principles).

System expansion via substitution is only applicable for a consequential approach, as the consideration of (hypothetical) alternatives is by definition consequential (See 4.1.3 Consequential approach). Substitution considers alternative production pathways of a co-product. The partial CFP associated with the substituted product(s) is subtracted from the product system under study (see Figure 4).

Figure 4 — Example of avoiding allocation by using system expansion via substitution (ISO 14044:2006 / AMD 2:2020).

Note: In this particular example, product B is an energy product, but could be any product.

The application of system expansion involves an understanding of the market for the co-products. Decisions about system expansion can be improved through understanding the way co-products compete with other products, as well as the effects of any product substitution upon production practices in the industries impacted by the co-products.

Important considerations relating to the identification of relevant substitution pathways include:

— Whether specific markets and technologies are affected;

— Whether the production volume of the studied product systems fluctuates over time;

— Whether a specific unit process is affected directly;

— If inputs are delivered through a market, it is also important to consider:

— whether any of the processes or technologies supplying the market are constrained, in which case their output does not change in spite of changes in demand;

— which of the unconstrained suppliers/technologies has the highest or lowest production costs and, therefore, is the supplier/technology affected when the demand for the supplementary product is generally decreasing or increasing, respectively.

The justification of the choice of system expansion can be based on technical considerations. System expansion via substitution can be a straightforward choice for energy products. But where there are multiple industrial pathways for co-products, the model results can have high variability. If there are different possibilities of substitution of a co-product, this can lead to significantly different results. Therefore, the substitute systems for each co-product should be defined and justified.

Step 2: Where allocation cannot be avoided, the inputs and outputs of the system should be partitioned between its different products or functions in a way that reflects the underlying physical relationships between them

Allocation of GHG emissions between different co-products in a way that reflects the underlying physical relationships between them is only applicable in an attributional approach. It is not applicable following a consequential approach, as this procedure does not evaluate any consequences of or alternative means to co-production.

Physical relationship: in many cases the input flows can be allocated to co-products based on the specific function they perform in relation to the individual co-products and/or the direct GHG emissions can be allocated to co-products based on an underlying relationship between the co-products and their emissions contribution. Possible physical parameters or combinations of some of them for allocation include energy content, mass, and mole.

The parameter selected for the allocation method should be consistent with the purpose of the hydrogen production facility and should reflect the reason why inputs are used and GHG are emitted.

It should be noted that considerable differences in allocation results may occur. For example, electricity used for water electrolysis coproduces hydrogen and oxygen. In case of oxygen valorization, a mass-based allocation will allocate 16 times more GHG emissions to oxygen than to hydrogen, while a mole-based allocation will allocate only half as many GHG emissions to oxygen as to hydrogen.

Step 3: Where physical relationship alone cannot be established or used as the basis for allocation, the inputs should be allocated between the products and the functions in a way that reflects other relationships between them.

Allocation of GHG emissions between different co-products in a way that reflects a relationship other than a physical relationship is only applicable in an attributional approach. It is not applicable following a consequential approach, as this procedure does not evaluate any consequences of or alternative means to co-production.

An example for an allocation method relying on a relationship other than a physical relationship is to allocate GHG emissions between co-products in proportion to the economic value of the co-products.

Such an allocation based on economic value may reflect the intention of operating a process. The relative revenues may impact choices in production, specifically whether to favor or produce more of one co-product over another. Economic allocation may help to reflect differences between regions and markets for similar products. Economic allocation has the potential to differentiate between similar products having different quality attributes. Economic allocation for hydrogen production specifically is complicated more in markets where the price of hydrogen depends on the CFP of hydrogen, therefore creating a circular argument which may make economic allocation impossible.

However, it should also be noted that market prices may vary over time, and between different regions and market actors. The selection of the allocation factors represents a value choice and the allocation factor may show a high uncertainty, especially for future scenarios. The application of allocation based on economic value depends on having market prices for all co-products. Furthermore, allocating based on cost- or revenue might not reflect the physical causalities of producing or purchasing a specific product. Therefore, economic allocation may only be used when a relevant physical relationship cannot be established.

The economic value shall be considered at the point (i.e. at plant/service provider), in the condition (e.g. not purified/technical quality), and in the amount (e.g. bulk) that co-products are provided by the multifunctional process. The specific market price shall be used as the economic value. If the co-products are not traded at that point of allocation and with their specific characteristics, the market price has to be derived by combining production cost information and the market price of the further processed, packed, transported co-product.

Any additional steps of transport, conditioning, packaging etc. are to be considered to make sure the economic value used for allocation reflects the value of each co-product at the point where and in the condition in which it is delivered.

After completing the CFP study of hydrogen, the applicant should prepare a CFP study report (per ISO 14067). Useful guidance can be found in GHG Protocol^[9][10][11].Critical review

In compiling the CFP study, a critical review facilitates understanding and enhances the credibility of CFP. A critical review of CFP studies, if any, shall be performed in accordance with ISO/TS 14071.

1. 
   (Normative)
   
   Hydrogen Purity
   1. Background

In practice, hydrogen production facilities are likely to produce gas streams that are not 100 % hydrogen because they contain traces of impurities (i.e., gases that are not hydrogen). A high purity hydrogen can be practically pure if impurities have negligible impact on the greenhouse gases (GHG) emissions calculation of hydrogen. A purity level of 99,9 % mole fraction of hydrogen (0,1 mole% impurities), for example 0,1 mole% of CO2 impurity, may add 0,022 kgCO2e/kg hydrogen (or < 0,2 gCO2e/MJ hydrogen) and increase the emission for 1 kg of pure H2 (@100 %).

For most hydrogen applications, the purity level requirement exceeds 99,9 %. The following are examples of the gaseous hydrogen (Type I) fuel quality specification in the ISO 14687:2019 for various stationery and vehicle applications with purity specification ≥99 %: grade B (99,9 % purity); grade E, category 3 (99,9 % purity); grade C (99,995 % purity); and grade D (99,97 % purity). Grade A and F have purity specification ≥98 %.

For hydrogen purity below 99,9 % mole fraction, the purity of hydrogen becomes significant for calculating GHG emissions of hydrogen considering two important factors:

(1) the amount of impurities (e.g., x% by mole) impacts the life cycle functional unit of hydrogen, typically a mass unit of 1 kg, especially when considering the much smaller molecular weight of hydrogen compared to most impurities (e.g., N₂, CO, CO₂, etc.) For example, 1 % of CO₂ impurity (mole basis, i.e., 99 % hydrogen purity) in 1 kg of the gas product represents 18 % of CO₂ by mass, thus only 0,82 kg is the share of H₂ in the 1 kg of gas product. This is in contrast with the assumed 1 kg of hydrogen product if the CO₂ impurity is ignored based on its small share on per mole basis.

(2) If the impurity contains non-biogenic carbon in its chemical composition (e.g., CO, CO₂, CH₄), such impurities can add to the GHG emissions of hydrogen assuming oxidation of the carbon containing impurity to CO₂ before being emitting to atmosphere. Considering the previous example, each 1 % (by mole) of non-biogenic CO and CO₂, and of CH₄ in the product gas will add 0,22 kg of CO₂ per kg of molecular H₂ to the GHG emissions of hydrogen assuming the oxidation of these carbon containing impurities before emitting to the atmosphere, whereas, if the produced hydrogen gas is not combusted, emissions of 1 % of biogenic or non-biogenic CH₄ (by mole) will increase the GHG emissions of hydrogen gas by the CH₄ equivalent CO₂ (i.e., by considering the global warming potential of biogenic and non-biogenic CH₄ according to IPCC). Thus, it is important to account for the fate of the non-biogenic carbon in the impurities, as well as the fate of the CH₄ impurity, and quantify their potential impact on the GHG emissions calculations of hydrogen product (kgCO₂e/kg hydrogen). The methodology described below provides details on how the GHG emissions of hydrogen in kgCO₂e/kg hydrogen can be calculated, considering the two factors mentioned above.

• 1. Method [Normative]

The following example describes how to account for impact of carbon containing and non-carbon impurities on the GHG emissions calculation of hydrogen product. In this example,

— y (kg CO₂e/kg hydrogen gas) is the sum of “raw material extraction to production gate” GHG emissions (direct and indirect) associated with the production of hydrogen gas leaving the hydrogen plant before accounting for carbon in impurities

— (mol H₂/mol gas) is the mole fraction of hydrogen in the hydrogen gas product (including impurities) leaving the hydrogen plant

— (mol CH₄/mol gas) is the mole fraction of methane in the hydrogen gas product (including impurities) leaving the hydrogen plant

— (mol CO/mol gas) is the mole fraction of non-biogenic carbon monoxide in the hydrogen gas product (including impurities) leaving the hydrogen plant

— (mol CO₂/mol gas) is the mole fraction of non-biogenic carbon dioxide in the hydrogen gas product (including impurities) leaving the hydrogen plant

— (mol N₂/mol gas) is the mole fraction of nitrogen in the hydrogen gas product (including impurities) leaving the hydrogen plant

— (mol H₂O/mol gas) is the mole fraction of water in the hydrogen gas product (including impurities) leaving the hydrogen plant

— (mol of species (i)/mol of hydrogen gas) is the mole fraction of product (including impurities) leaving the hydrogen plant

— (g H₂/mol H₂) is the molecular weight of H₂

— (g CH₄/mol CH₄) is the molecular weight of

— (g CO/mol CO) is the molecular weight of carbon monoxide

— (g CO/mol CO₂) is the molecular weight of carbon dioxide

— (g N₂/mol N₂) is the molecular weight of nitrogen

— (g H₂O/mol H₂O) is the molecular weight of water

— (g gas/mol gas) is the molecular weight of gas

— (g species i/mol species i) is the molecular weight of species i

If the non-biogenic carbon content impurities and CH₄ in the hydrogen gas product are assumed to be completely oxidized (e.g., combusted), then the mass of CO₂ emitted from these impurities per unit mass of molecular H₂ will be calculated according to Equation A.1:

(A.1)

If the produced hydrogen gas is not completely oxidized, in this case, assuming that methane is not oxidized and is released to the atmosphere, but that CO is completely oxidized, the emissions of biogenic or non-biogenic CH₄ will be accounted for according to the IPCC global warming potential (GWP) of biogenic and non-biogenic CH₄. In this case, the GHG emissions from these impurities in mass unit of CO_2e per unit mass of molecular H₂ will be calculated according to Equation A.2:

(A.2)

Considering the unit mass of hydrogen gas product (instead of unit mass of molecular H₂) as the functional unit, the mass of CO₂ emitted upon complete oxidation or combustion of hydrogen gas product (including impurities) can be calculated according to Equation A.3:

(A.3)

or, if CH₄ is emitted instead of combusted, c’ will be calculated according to Equation A.4:

(A.4)

Where in this case is given in Equation A.5.

(A.5)

The GHG emissions of the gas product (excluding impurities) leaving the hydrogen plant in units of (kg CO_2e / kg hydrogen gas produced, including impurities) can be calculated according to Equation A.6:

(A.6)

The GHG emissions of the molecular hydrogen component (H₂) of the gas product (excluding impurities) leaving the hydrogen plant in units of (kg CO_2e / kg hydrogen) can be calculated according to Equation A.7:

(A.7)

These emission factors shall be calculated by the hydrogen gas producer and provided to recipients of hydrogen gas (including quantitative description of impurities) for potential use in the life cycle assessments of products manufactured from hydrogen gas, including its end use.

If the hydrogen gas (including impurities) is employed by its recipient as a fuel (i.e., completely combusted), then the life cycle GHG emissions per unit of the combusted hydrogen gas fuel (including impurities) at end use application, assuming no mass losses in the hydrogen gas transport, can be calculated according to Equation A.8:

(A.8)

or the life cycle GHG emissions per mass unit of the molecular hydrogen product can be calculated according to Equation A.9:

(A.9)

The preceding formulas require that the hydrogen production facility measures the mass flow rate of the (H₂ + impurities) gas product and the chemical composition (mol%) of each impurity in the hydrogen product gas, including that of hydrogen (mol%) (e.g., via gas analyzer).

In the attributional approach, the CFP of the hydrogen gas (including impurities) at the hydrogen production facility is y, as previously described, and the fate of remaining (non-biogenic) carbon in the impurities shall be accounted for in the downstream use of hydrogen gas (including impurities) according to equations A.7 and A.8.

In a consequential approach that accounts for the fate of carbon in impurities at end use application of hydrogen gas (including impurities), c’ shall be included in the CFP of hydrogen according to equations A.5 and A.6 if the fate of non-biogenic carbon in the impurities is known or assumed to be CO₂ in the atmosphere, except for CH₄ when the hydrogen gas is not used as fuel, in this case the CH₄ greenhouse effect should be accounted for with its global warming potential (GWP) according to IPCC. If the hydrogen gas (including impurities) is ultimately used in a process that captures and sequesters the carbon in the impurities (i.e., does not release it as GHG to the atmosphere), then including c’ in the partial CFP of hydrogen gas (including impurities) is inappropriate.

1. 
   (informative)
   
   Consequential Approach—Examples for Hydrogen Production
   1. Overview

A consequential approach includes GHG emissions within the product system boundary, and considers possible GHG emissions that occur outside the boundaries of the product system.

This annex provides an overview of different applications of the consequential approach, moving from a rather limited application of the consequential approach to broader applications, including:

(1) System expansion to avoid allocation,

(2) System expansion to include specific upstream consequences of the production,

(3) System expansion to include downstream consequences of the usage of the product, and

(4) Macro-economic modelling.

For each of these four applications, this annex also provides examples.

In this document, for a Carbon Footprint of a Product, a consequential approach may be employed in the limited way corresponding to the use of “system expansion via substitution” to avoid allocation when a unit process yields multiple co-products. These co-products may displace alternative methods of production. When a consequential approach is used for a broader impact assessment, the GHG inventory is expanded beyond the boundaries of the hydrogen value chain from the raw material extraction to the production gate, considering operations outside the boundaries of the product system. By definition such approaches are outside the scope of this document.

• 1. System expansion to avoid allocation

System expansion to avoid allocation refers to expanding the analysed system to consider alternative production pathways of the co-products as a way to account for the impact of displacing co-products manufactured via other means. Two different methods exist for system expansion:

1. System expansion via changing the functional unit to include hydrogen and other co-products:

The “system expansion via changing the functional unit to include hydrogen and other co-products” approach allows to define the functional unit so that it comprises a mix of all co-products reflecting the share of each of the co-products. For example, steam methane reforming (Annex D) often yields hydrogen, steam, and CO. Introducing a functional unit that comprises all three co-products makes it possible to avoid allocation.

System expansion via changing the functional unit to include hydrogen and other co-products is not aligned with this standard, which defines the functional unit as 1 kg of hydrogen (See 4.2.1.1 General principles).

2. System expansion via substitution, displacement, or avoided burden method:

According to ISO 14044:2020 amd 2: “System expansion [via substitution] avoids allocation by integrating a functionally equivalent product system, that is assumed to be substituted by the co-product, within the system boundary”.

System expansion via substitution may be used to estimate the emissions associated with a co-product based on the emissions associated with producing that co-product using an alternative production method. When using substitution, the functional unit remains unchanged (i.e., 1 kg of hydrogen as defined in 4.2.1.1 General principles), and the environmental impacts associated with alternative production method of the co-products are subtracted from the product system under study (Figure B.1).

Figure B.1 — System expansion via substitution

Example: substitution of steam as a co-product when producing hydrogen via steam methane reforming:

Steam Methane Reforming (Annex D) often yields both hydrogen and steam. The “system expansion via substitution” approach treats the steam co-product as “Product B” in Figure B.2, and subtracts an appropriate “steam product system” from the system boundary as illustrated in Figure B.2. The alternative (or reference) steam production system is defined by the LCA goal, and should reflect the most prevalent alternative method of producing steam in a region or sector. For example, the most prevalent alternative method to produce steam may be a natural gas-fired boiler in certain regions, but a coal-fired boiler, oil fired boiler, or electric boiler in other regions.

• 1. System expansion to include specific upstream consequences of the production

System expansion to include specific upstream consequences of the production refers to expanding the analysed system to consider inputs, and emissions associated with these inputs, that would otherwise be considered in another product system.

Example: Production of biogas from manure:

The system is expanded to take into account the emissions of CH₄ that would occur in the absence of the biogas production as a counterfactual scenario. The expanded system includes the production of the livestock producing the manure. To determine the emissions avoided by the biogas production, the livestock farm without biogas production is subtracted from the system under study. The methane emissions to the atmosphere resulting from the manure decomposition are therefore subtracted from the emission inventory of the system under study. Such a consequential approach results in a negative inventory for the production of biogas from manure due to the high GWP of Methane. The carbon intensity of the biogas may be negative because it takes into account counterfactual emissions from livestock farming that would have occurred if the biogas had not been diverted and used as a feedstock.

Note1: Under such an approach, the livestock product should keep counting the methane emissions (which do not occur) in the product carbon footprint of its product.

Note 2: Under ISO 14067, there is no methane emissions in the GHG inventory, as the methane is not released into the atmosphere when biogas is produced.

• 1. System expansion to include specific downstream consequences of the production

System expansion to include specific downstream consequences of the production refers to expanding the analysed system to consider emissions associated with the utilisation of the product—e.g. hydrogen—or of other outputs—e.g. methanol, CO₂—that would otherwise be considered in another product system.

Example, Inclusion of emissions occurring during the usage of a co-product: Figure B.2 illustrates how the analysed system may be expanded to include emissions associated with the usage of CO₂, when CO₂ is a co-product of hydrogen.

Figure B.2 — Comparison of attributional and consequential approaches for the accounting of emissions resulting from CCU

• 1. Macro-economic modelling

Macro-economic modelling refers to expanding the analysed system to consider indirect effects related to the (increased) production, transport or use of the analysed product.

It is important to note that consequential analysis involving macro-economic modelling involves considerable uncertainties that are likely higher compared to previously mentioned methods because it attempts to estimate future market response to a large-scale production, transport and use of a product. Attempts to model future market response must incorporate numerous assumptions regarding future demand, prices, price elasticities, interaction with other sectors, and oftentimes cannot account for things like geopolitical uncertainties or major market developments (e.g., disruptive technological developments).”

The following examples are drawn from the European Union directive 2023/2413, which provides a methodology for assessing the life-cycle GHG emissions associated with the production, transport and use of hydrogen, incorporating consequential elements. This amending directive is a revision of the Renewable Energy Directive EU/2018/2001 that entered into force on 20 November 2023. The exact methodology to estimate the emissions savings of hydrogen produced from renewable sources and other renewable fuels of non-biological origin (RFNBOs) is set out in the delegated regulation 2023/1185.

The main consequential items of the EU/2023/2413 directive are:

Example 1, consequential approach for treatment of electricity (EU Renewable Energy Directive)

Consequential approaches for treatment of electricity are of particular relevance for policymakers, interested in the direct and indirect impacts of expanding hydrogen production and aiming at reducing negative (unintended) effects. For example, independent of whether electricity is purchased on the generic electricity market or from a specific supplier, the EU/2023/2413 directive aims to account for effects that are expected in reaction to a change in demand for electricity.

Specifically, the directive aims to avoid the diversion of electricity generated from existing renewable capacity serving existing loads on the grid to service the large-scale deployment of hydrogen production (e.g., water electrolysis). Such a shift could then result in more fossil-based electricity generation to compensate for the renewable electricity being directed to hydrogen production, resulting in negative or marginal net environmental benefits from hydrogen production using electricity from renewable sources.

For that purpose, the directive considers additionality, temporal correlation, and geographic correlation as relevant conditions to avoid inadvertent expansion of fossil-based electricity generation on the grid as a result of an increase in hydrogen production. Introducing the conditions of additionality, temporal correlation, and geographic correlation is a specific application of a consequential approach because the GHG emissions attributed to the electricity input is calculated based on an expected change in grid emissions in response to a change in electricity demand.

Example 2, distinction between elastic and rigid inputs (EU Renewable Energy Directive)

In the EU Renewable Energy Directive, the estimation of GHG emissions differentiates between rigid and elastic inputs. Inputs are considered rigid when their supply cannot be expanded to meet additional demand. Inputs are considered elastic when their supply can be increased to meet additional demand. If rigid inputs are used, the impact of diverting them from their previous use have to be included. This approach is consequential because it accounts for the change in emissions due to a change in demand.

Example 3, comparison with a counterfactual scenario (EU Renewable Energy Directive)

The EU Renewable Energy Directive aims to promote the use of energy from renewable sources. It sets an overall target of renewable energy accounting for at least 42,5 % of fuel consumption at EU level by 2030. Hydrogen produced from renewable sources can count towards the EU’s renewable energy target if it leads to more than 70 % GHG emissions savings compared to the use of the fossil fuel it is replacing. This target setting is another example of a consequential approach, as the threshold for GHG emissions intensity of hydrogen is determined with respect to a reference scenario.

Example 4, substitution for special cases (EU Renewable Energy Directive)

EU/2023/2413 includes a system expansion approach for the case of biogas from manure, where the emissions from a counterfactual scenario are subtracted from the biogas GHG inventory (because the emissions resulting from the direct use of manure are avoided) (see Example 1 in Section B.3)

The same approach is used by several other regulations such as IRA, LCFS, RFS, etc.

Example 5, GHG emissions associated with indirect land use change

Consequential analysis may also be used to estimate the potential change in GHG emissions associated with indirect land use change from large-scale production of biogenic feedstock.

1. 
   
   Feedstocks for Hydrogen Production
   1. Carbon Footprint of Feedstocks

The system boundary for intentionally-manufactured feedstocks shall include operations associated with the acquisition of raw materials, their transformation into feedstocks, and the transportation of feedstocks to the hydrogen plant. The carbon footprint of a feedstock shall account for emissions associated with these operations.

The functional unit of a feedstock shall be the quantity delivered to the hydrogen plant.

carbon footprints of electricity and natural gas inputs to a hydrogen plant are addressed in 4.3.2.5.2 (Treatment of electricity) and 4.3.2.5.4 (Treatment of natural gas) respectively.

For other feedstocks, depending on the available data, calculation of the emission factor of the feedstock (as energy or material feedstock) can be performed in the following priority order:

1) using a carbon footprint derived from direct measurements, where practical and applicable, at the source-level of the feedstock purchased that is verified by an independent, third-party verifier (see 3.5.5 site-specific data); or if not available

2) using a well-documented carbon footprint utilized by the industry producing the feedstock based on independent, third party, publicly-funded scientific analysis; or if not available

3) using a carbon footprint provided by a national authority, or a data source which is generally used in the country or area where the feedstock is manufactured, or otherwise globally used LCA database.

If carbon footprints from such sources are used, then they should be explicitly reported where practical and applicable. If the value of the carbon footprint of a feedstock from such sources cannot be disclosed explicitly (e.g. due to terms and conditions of an LCA database), then the version of the database shall be provided. GHG emissions associated with transport of the feedstock to the hydrogen production facility shall be accounted for following the same above rules on emission factors.

• • 1. Estimation of the Carbon Footprint

In Case C.1 1) above, the system boundary of the feedstock shall be explicitly defined.

• • • 1. Intentionally manufactured feedstocks [Normative]

The system boundary for intentionally-manufactured feedstocks shall include operations associated with the acquisition of raw materials, their transformation into feedstocks, and the transportation of feedstocks to the hydrogen plant. The carbon footprint of a feedstock shall account for emissions associated with these operations.

• • • 1. Wastes

ISO 14067 precludes allocation of impacts to waste (“When outputs include both co-products and waste, the ratio between co-products and waste shall be identified and the inputs and outputs shall be allocated to the co-products only.”).^[1] Accordingly, the system boundary associated with “utilized waste” (defined as a material that formerly had no market value or negative market value, but obtained positive market value via one or more treatment operations) excludes the process that originally generated the waste material, as well as upstream environmental impacts associated with that waste-generating process. The system boundary of the waste feedstock also excludes operations associated with the transportation of waste from the waste generator (where the market value is zero or negative) to the processing facility (where the waste acquires a positive market value) – those operations should fall within the system boundary of the product(s) that generated the waste.

If the carbon in biogenic waste is atmospheric in origin (e.g. food waste), then decay of that waste would return a portion if not all of that carbon to the atmosphere if the waste wasn’t utilized as a feedstock. ISO 14067:2018 states “Biogenic GHG emissions and removals shall be included in the CFP or the CFP and should each be expressed separately”. Reasonable efforts should be made to avoid double-counting of emissions or removals associated with biogenic carbon associated with the waste-generating product system and the waste-feedstock product system.

Regardless of the waste’s origin, the system boundary includes operations associated with processing and transportation of wastes with positive economic value to the hydrogen plant for use as hydrogen feedstocks as below C.1.1.2.1 and C.1.1.2.2.

• • • • 1. System Boundary for Attributional Approach [Normative]

A general system boundary for an attributional approach to estimating a carbon footprint of waste feedstock is illustrated in Figure C.1.

Figure C.1 — System boundary for waste feedstocks (attributional)

In this figure, W is a quantity of material generated by another manufacturing process having zero or negative market value. Since the producer of this material must pay another party to dispose it, this material is a waste of another manufacturing process. Therefore, emissions associated with the manufacturing process that generates the waste stream of mass W are not allocated to the material denoted “Waste” in Figure C.1.

The “Waste Processing” operations convert the negatively-valued material to positively-valued material. Therefore, emissions (direct and indirect) associated with waste processing^[7] (Y_P kg CO₂e) and feedstock transport (Y_T kg CO₂e) must be accounted when assessing the carbon footprint of the (positive-market-valued) “Feedstock” derived from (negative-market-valued) “Waste”. Some operations associated with waste processing produce a waste stream that has not yet obtained a positive market value; those operations would fall outside the system boundary illustrated in Figure C.1. The attributional carbon footprint associated with the feedstock to the hydrogen plant is calculated in Equation C.1.

(C.1)

In Equation C.1, (kg biogenic carbon/kg unprocessed waste) is the fraction of the waste composed of biogenic carbon, is the molecular weight of carbon dioxide, and is the molecular weight of carbon. The bracketed term in the numerator of Equation C.1 may be interpreted as a credit for photosynthetic removal of CO₂ from the atmosphere by biomass, which may be directly or indirectly the source of the waste. If the waste is entirely biogenic (e.g. agriculture residues), then . If the waste is entirely fossil-derived (e.g. waste polystyrene completely derived from petroleum), then .

ISO 14067:2018 states “Biogenic GHG emissions and removals shall be included in the CFP or the CFP and should each be expressed separately”^[1]. Reasonable efforts should be made to avoid double-counting of emissions or removals associated with biogenic carbon associated with the waste-generating product system and the waste-feedstock product system.

• • • • 1. System Boundary for Consequential Approach [Informative]

A general system boundary for a consequential approach to estimating a carbon footprint of waste feedstock is illustrated in Figure C.2.

Figure C.2 — System boundary for waste feedstocks when the default waste disposal process does not generate electricity (consequential)

In this figure, W is the mass of (zero or negatively valued) waste originally generated by another manufacturing process. Since the producer of this material must pay another party to dispose it, this material is a waste of another manufacturing process. Therefore, emissions associated with the manufacturing process that generates the waste stream of mass W are not allocated to the material denoted “Waste” in Figure C.2. However, direct and indirect emissions are generated as part of waste transport and processing (Y_P kg CO₂e) and feedstock transport (Y_T kg CO₂e). Since this is a consequential analysis, the (direct and indirect) emissions that would have occurred during waste disposal (Y_D kg CO₂e) are subtracted from the emissions in the waste valorization scenario (sometimes referred to as an “avoided burden approach”). Therefore, the carbon footprint associated with the feedstock to the hydrogen plant is calculated according to Equation C.2:

(C.2)

Here, (kg biogenic carbon/kg unprocessed waste) is the fraction of the waste composed of biogenic carbon, is the molecular weight of carbon dioxide, and is the molecular weight of carbon. This may be simplified according to Equation C.3:

(C.3)

Note that in this case, the biogenic terms cancel. However, if all biogenic carbon in the waste is converted to CO₂ during “Waste Disposal”, then , and the results of Equations C.2 and C.3 will be the same, provided that the guidance of ISO 14067:2018 is followed: "In the case of products from biomass, carbon storage is calculated as carbon removal during plant growth and subsequent emission if the biogenic carbon is released in the use or end of life stages.” (see also Figure C.1).

NOTE: Another way to express this is that in the case of biogenic carbon yielded in the waste, the decay of that waste would have returned at least part of carbon to the atmosphere, if it wasn’t utilized as a feedstock.

For the purposes of consistency, as illustrated in Figure C.2, waste disposal emissions should be accounted for in the counterfactual system boundary and corresponding inventory. Double-counting of emissions associated with valorization and disposal must not occur.

In the preceding discussion, , and are all potentially different due to loss or gain of moisture or changes in composition (e.g. changes due to consumption of waste by microorganisms). Changes in composition resulting in emissions must be accounted within and .

If the counterfactual waste disposal process is a waste utilization process that generates electricity and/or steam then the consequential system boundary should also include operations associated with the production of an equivalent amount of electricity and/or steam from the waste that was diverted and used for hydrogen production instead to account for the consequence that electricity and/or steam must now be produced from an alternative feedstock. In Figure C.3, a system boundary is illustrated with a waste disposal process that co-produces electricity, but a completely analogous system boundary could be illustrated for a waste disposal process that co-produces steam, or a combination of steam and electricity.

Figure C.3 — System boundary for waste feedstocks, when the default waste disposal process does generate electricity (consequential)

In this case, is calculated according to Equation C.4:

(C.4)

In Equation C.4, (kg CO₂e) are the life cycle GHG emissions associated with electricity that replaces the P (kWh) of electricity formerly generated via the utilization of waste.

It is possible that other counterfactual scenarios may be more appropriate than those illustrated in Figures C.1, C.2, and C.3 for certain feedstocks (e.g. scenarios where waste is combusted and used to generate district heating or combined heat & electricity in the “disposal” scenario). Annex B provides additional guidance regarding the application of consequential LCA.

• 1. Illustrative Examples [Informative]

More details concerning the various waste feedstock’s LCA, as well as some examples for hydrogen production can be found in the ILCD Handbook^[2] and IPHE's Methodology for Determining the Greenhouse Gas Emissions Associated with the Production of Hydrogen^[3].

Specific examples are provided below:

• • 1. Coal as a feedstock for gasification processes

Coal is a potential feedstock for hydrogen manufacture via gasification (Annex H). The carbon footprint of coal received by the gasification facility includes upstream activities associated with the extraction, processing and delivery of the coal feedstock (Figure C.4).

Figure C.4 — Operations included in the carbon footprint of coal utilized as a feedstock for hydrogen production

The carbon footprint of coal extracted from different regions may be estimated in different ways (e.g. collection of primary or secondary data to estimate a local or regional emission factor, or use of an indirect emission factor that should at a minimum be country specific). As the coal production system has a single product, allocation is unnecessary and all emissions associated with the operations illustrated in Figure C.4 are normalized with regard to a single output, i.e. the mass of coal to be gasified. Where applicable, a detailed assessment of the carbon footprint of each type of coal supplied to the hydrogen plant may be bypassed via use of carbon footprints provided by a national authority, or data source which is generally used in the country or area where the coal is extracted, or otherwise a globally used LCA database.

• • 1. Biomass as a feedstock for thermochemical processes

Thermochemical pathways for biomass conversion into hydrogen include pyrolysis, liquefaction, or gasification, followed by other steps at the hydrogen plant. Thermochemical pathways aim to promote cracking reactions under severe thermodynamic conditions, so to break down large biomolecules into lower molecular weight chemical species.

As most hydrogen production from biomass is still in the early commercial stage, it is difficult to define standardized production pathways, especially for cases that include CCS.

For a solid biomass waste feedstock, the attributional and consequential approaches illustrated by Figure C.1, Figure C.2 and Figure C.3 may be employed, where the default method of disposal of the waste feedstock must be explicitly specified. If the biomass is typically grown for sale, then it should not be considered a waste. The three-stage procedure discussed in C.1 Carbon Footprint of Feedstocks may be employed to estimate the carbon footprint associated with solid biomass, including removals of atmospheric carbon.

• • 1. Biogas as a feedstock

Biogas^[8] is predominantly produced from agriculture waste, animal manure, sewage sludge and disposed organic waste in landfills and often consists of methane (40-65 % by mole), carbon dioxide (35-55 % by mole), as well as hydrogen sulfide (H₂S), oxygen, nitrogen, ammonia, and other contaminants. Biogas is a potential feedstock for processes using natural gas, such as methane reforming technologies (Annex D) and methane pyrolysis (Annex I).

The carbon footprint of biogas feedstock to a hydrogen plant must include GHG emissions associated with the treatment of the gas - when treatment is applicable -, for use as a feedstock for hydrogen production, as well as transportation emissions. The carbon footprint may be estimated using the attributional approach or consequential approach.

The “Waste Transport and Processing” subsystems illustrated in Figure C.1, Figure C.2, and Figure C.3 may resemble the process illustrated in Figure C.5. Operations within the subsystem include pre-treatment of the feedstock, transport from the site of waste generation, processing and transport to the hydrogen plant (not illustrated). A potential co-product from this process is fertilizer feedstock consisting of solid and/or liquid matter. Biogenic CO₂ may also be a co-product, or may be emitted, returning formerly-atmospheric CO₂ to the atmosphere. Care must be taken to ensure that emissions or removals of biogenic CO₂ are not double counted among possible co-products, and that biogenic CO₂ in the biogas feedstock is appropriately accounted in the carbon footprint.

Figure C.5 — An example of process diagram for the upstream system to deliver biogas mixture for upgrading and/or reforming

1. 
   
   Hydrogen Production Pathway – Methane Reforming (with or without Carbon Capture and Storage)

Methane Reforming is the endothermic/catalytic reaction of methane (and potentially ethane, propane and other light hydrocarbons) with water or O₂ to make H₂, CO, and CO₂. Predominant technologies include steam methane reforming (SMR), autothermal reforming (ATR), and partial oxidation (POX), however, many other technologies are in varying stages of development. The methods discussed in this Annex are intended to provide guidance for all such technologies. Illustrative examples are provided only for specific SMR and ATR processes.

Carbon capture technologies may be employed for many methane reforming processes.

• 1. Steam Methane Reforming (with or without Carbon Capture and Storage)
     1. SMR/CCS process description and overview [informative]

Sections D.1.1.1 and D.1.1.2 provide a description and an overview for hydrogen produced from steam methane reforming with carbon capture and storage.

• • • 1. Description

Currently, steam methane reforming (SMR) is the leading technology for hydrogen production from natural gas or light hydrocarbons.

An SMR production plant is typically composed of the following sub processes:

— A gas pretreatment plant, possibly including a sulfur removal unit (not shown)

— A reformer^[9] where the feedstock is reacting with water to produce syngas composed mainly of H2 and carbon monoxide (CO). The main reaction is CH₄ + H₂O → CO + 3 H₂

— A “Cold Box” separating CO in case CO is valorized as a co-product (optional)

— A Water Gas Shift (WGS) reactor that reacts CO in the syngas with water to carbon dioxide and H2 via the following chemical reaction: CO + H₂O → CO₂ + H₂

— A Pressure Swing Adsorption unit (PSA) to purify the hydrogen

— A Carbon Capture Unit (optional)

In an SMR facility, GHG emissions result from combustion of fossil fuels for heat and steam, as well as venting and fugitive emissions. Modern SMR based hydrogen production facilities have achieved efficiencies that could reduce CO₂ emissions down to nearly 10% above its theoretical minimum. Further reduction of CO₂ emissions from hydrogen production may be possible with CCS.

• • • 1. Overview

A block flow diagram for one example of a SMR featuring CO₂ capture on the PSA tail Gas is described in Figure D.1.

Figure D.1 — Example of a simplified SMR plant block diagram

• • 1. Emission sources and inventory

Sections D.1.2.1, D.1.2.2 and D.1.2.3 provide the emissions sources and inventory in case of attributional approach and consequential approach for hydrogen produced from steam methane reforming with carbon capture and storage.

• • • 1. Emission sources [informative]

For SMR, the main source of GHG emissions is the combustion of fossil fuel to provide heat to convert methane into syngas and venting of CO₂ generated by the WGS reactor. Other emission sources may include

— Emissions associated with the production and transportation of process inputs (feedstock and energy);

— Emissions associated with purchased electricity for the operations illustrated in Figure D.1;

— Direct emissions of CO₂, methane, or other greenhouse gases at the hydrogen plant due to unmitigated combustion or venting

— Direct and indirect emissions associated with operation of CO₂ pipelines and facilities delivering CO₂ to permanent geological sequestration (CCS).

Emissions sources of each process unit or stage in the SMR process are outlined in Table D.1.

Table D.1 — Potential GHG emissions in the life cycle of hydrogen produced via SMR

• • • 1. Inventory in case of Attributional Approach [normative]
         1. Energy supply and upstream emissions:

GHG emissions associated with hydrogen plant third-party feedstocks, including natural gas, steam and electricity are evaluated based on 4.3.2.5.4, 4.3.2.5.3, 4.3.2.5.2 and Annex C.

• • • • 1. Direct emissions at production:

The quantity of CO₂ released into the atmosphere during the hydrogen production stage may be estimated using the carbon balance within the boundaries of the plant. The total carbon input is determined from the quantity and characteristic of the feedstock and fuel. The total carbon output is the sum of

— Carbon in the CO₂ emitted

— Carbon in the CO₂ captured (used or sequestered)

— Carbon in the CO produced and used, if any, and

— Carbon in the hydrogen product (i.e. impurities)

— Emissions of other possible carbon-containing species emitted, such as methane, volatile organic compounds (VOC), and CO.

NOTE: Other GHG emissions, such as N₂O, shall be accounted for.

• • • 1. Inventory in case of Consequential Approach [informative]

In case of a consequential approach, the inventory may include inventories associated with displaced/substituted co-products. The goal of the LCA should define the boundaries to take into account for consideration of GHG emissions or emissions reductions associated with hydrogen production outside of the hydrogen system boundary.

For instance, the inventory may include the emissions expected from conventional means to produce the co-products (substitution methods).

See Annex B for more details on consequential approaches to carbon footprinting.

• • 1. Emission Allocation

Several co-products may exist for a SMR with CCUS, including steam, CO, electricity, and CO₂. The specific co-products will depend on the design of the hydrogen plant.

• • • 1. Allocation: Attributional Approach [normative]
         1. Partitioning

As described at 4.3.3, the first step for the emission allocation is to subdivide the process [normative].

Process subdivision

For example, the process in Figure D.2 may be subdivided into 3 sub-processes:

— Sub-process 1 - The SMR Reactor. This sub process has natural gas, or other hydrocarbons, as well as process water as process inputs, syngas and steam as co products, and direct GHG emissions, predominantly CO₂ resulting from combustion of natural gas fuel. Syngas is mainly composed of H₂, CO, some traces of CO₂ and other impurities such as N₂ and unreacted methane.

Syngas generated in the SMR is then split, feeding the following two sub processes:

— Sub-process 2 – H₂/CO production unit: This sub process has syngas as input and H₂ and CO as co products, and CO₂ emissions. Note: The ratio between H₂ and CO in the syngas is a process design characteristic for an SMR. It is typically approximately 2,5 mole H₂ per mole of CO. The actual design characteristic of the considered plant should be used to determine this ratio and derive the quantity of hydrogen production considered as a co-product of CO.

— Sub-process 3 - Water Gas Shift + Carbon Capture (optional): This sub process has syngas and steam as inputs and hydrogen and CO₂ as outputs. In case of CCUS, CO₂ is considered as a co-product (CCU) or a waste (CCS).

Figure D.2 — An example of SMR plant block diagram -Subdivision in sub processes

Allocation

Emissions associated with each sub-process (and its inputs) are allocated to the products of those sub-processes.

— Sub-process 1 – SMR Reactor: Emissions associated with natural gas feedstocks and other inputs to sub-process 1 as well as the direct emissions associated with sub-process 1 are allocated to the syngas and steam co-products of sub-process 1 prorata their energy content (LHV^[10] or, in case of the steam, the enthalpy difference between steam at export conditions (temperature, pressure, quality) and water at plant feed condition).

The carbon footprint of syngas estimated from this step is subsequently used to estimate emissions associated with the feeds to sub-processes 2 and 3 prorata the energy content (LHV) of their co-products. In case of carbon capture, refer to Section 4.3.2.2.

Sub-process 2 – H₂/CO production unit: The direct emissions from sub-process 2 determined as described in D.1.2.2.2 are added to the emissions associated with the syngas fed to sub-process 2 and allocated to hydrogen sourced from the Cold Box (“Hydrogen from CB”) and CO as per their respective energy content (LHV). In case of carbon capture, refer to Section 4.3.2.2.

— Sub-process 3 – Water Gas Shift: The direct emissions from sub-process 3 determined as described in D.1.2.2.2 are added to the emissions associated with the syngas fed to sub-process 3. To these emissions, direct and indirect emissions associated with transportation and sequestration of CO₂ placed in permanent geological storage (CCS) must be added. The sum of these emissions is allocated to (a) hydrogen sourced from the shift reactor (“Hydrogen from shift”) and (b) CO₂ sold as a product (“CO₂ (CCU)”). Allocation methods for CO₂ follow Section 4.3.2.2.

NOTE: This procedure yields two carbon footprints – one for each of the two “types” of hydrogen leaving sub-processes 2 and 3 (“Hydrogen from shift” and “Hydrogen from CB”). A single carbon footprint may be calculated as a mass average of these two streams.

• • • 1. Allocation: Consequential Approach [Informative]

Under a consequential approach, the allocation of emission to co-products may be avoided by applying substitution / system expansion with displacement as described in 4.3.3.

If a hydrogen plant produces steam in addition to hydrogen, then the co-product steam shall be considered to displace steam of equivalent enthalpy (temperature, pressure, and quality) generated by combustion of fuel in a boiler. The displaced boiler efficiency shall be representative of the efficiency of boilers of equivalent size used to generate steam in the country where the hydrogen plant is located, or otherwise specified by governmental policy.

Expressed symbolically in Equation D.1.

(D.1)

In this equation,

— is the consequential “Raw Material Extraction to Production Gate” carbon footprint of hydrogen manufactured via the process illustrated in Figure D.1.

— (kgCO2e) is the sum of all GHG emissions at the hydrogen plant illustrated in Figure D.1,

— are the carbon footprints of inputs to the hydrogen plant illustrated in Figure D.1 (kgCO₂e/kg feedstock for material inputs and kgCO₂e/kWh for purchased electricity)

— are the flowrates of inputs to the hydrogen plant illustrated in Figure D.1 (kg/hr for material inputs and kW for purchased electricity),

— is the carbon footprint (raw material extraction through production) of steam displaced by the hydrogen plant illustrated in Figure D.1 (“Steam(heat)”)

— is the carbon footprint (raw material extraction through production) of CO₂ displaced by the hydrogen plant illustrated in Figure D.1 (“CO₂(CCU)”)

— is the carbon footprint (raw material extraction through production) of carbon monoxide (CO) displaced by the hydrogen plant illustrated in Figure D.1.

— is the sum of flowrates (kg/hr) of hydrogen produced by the hydrogen plant illustrated in Figure D.1 (“Hydrogen from CB” + “Hydrogen from shift”)

— is the flowrate (kg/hr) of steam displaced by the hydrogen plant illustrated in Figure D.1 (“Steam (heat)”)

— is the flowrate (kg/hr) of carbon monoxide displaced by the hydrogen plant illustrated in Figure D.1 (“CO”)

— is the flowrate (kg/hr) of utilized carbon dioxide displaced by the hydrogen plant illustrated in Figure D.1 (“CO₂”)

If the hydrogen plant displaces steam generated by a natural gas boiler in the region of the hydrogen plant, then the CFP of in Equation D.1 may be calculated as Equation D.2.:

      (Carbon footprint of displaced steam) (D.2)

Here,

— is the carbon footprint of natural gas (kgCO2e/kgNG),

— is the emission factor for natural gas combustion (kgCO2e/kgNG),

— is the LHV of natural gas (kJ/kg natural gas)

— is the LHV efficiency of the displaced natural gas boiler. And

— is the specific enthalpy difference between steam at export conditions (temperature, pressure, quality) and water at plant feed condition (kJ/kg steam)

If the hydrogen plant displaces steam generated by a boiler using a different fuel, then the natural gas-specific terms in Equation D.2 should be replaced with those of the other fuel. The choice of fuel for steam generation may vary by region, and must be justified and disclosed explicitly to stakeholders. carbon footprints of other fuels (e.g. coal or fuel oil) should be selected according to the criteria in Annex C.

Similarly, the CFPs of CO₂ and CO in Equation D.1 (displaced by CO₂ and CO produced at the hydrogen plant) should be representative of CO₂ and CO feedstocks in the region of the hydrogen plant. The source of CO₂ feedstocks may vary by region, and must be justified and disclosed explicitly to stakeholders.

• • 1. Information to be reported [Normative]

Table D.2 shows the information to be reported for hydrogen produced from steam methane reforming with carbon capture and storage.

Table D.2 — Information to be reported for SMR /CCS

• 1. Autothermal Reforming (with or without Carbon Capture and Storage)
     1. Process description and overview [Informative]

Sections D.2.1.1 and D.2.1.2 provide a description and an overview for hydrogen produced via the autothermal reforming process with or without carbon capture and storage.

• • • 1. Description

An autothermal reformer (ATR) is typically considered ‘self-heating’ as it includes the exothermic oxidation of methane which provides enough heat to support the concurrent endothermic reforming reaction.

As with the SMR process described in D.1, methane is first partially oxidized to produce syngas, although the ratio of hydrogen and carbon monoxide is typically different from SMR due to the chemical reactions involved. Moreover, the ATR does not require any heat from an external source, although other external heating operations may still be required, such as pre-heaters. The partial oxidation reaction is exothermic and provides the required heat to the concurrent steam reforming reaction, taking place in the ATR, in which methane and steam reacts to produce carbon monoxide and hydrogen in the reformer fixed catalyst bed. The syngas stream is then fed to the water-gas shift reactor(s) to further convert the carbon monoxide and excess steam into hydrogen and CO₂.

Unlike the SMR process, the ATR process utilizes oxygen as a process input. This is typically sourced from an air separation unit (ASU). The partial oxidation reaction occurs in the top section of the auto thermal reformer.

Whereas SMR typically requires post-combustion CO₂ capture, in ATR CO₂ capture may be achieved entirely through capture of process CO₂ from the hydrogen product stream. This may be conducted before or after the hydrogen purification step, using chemical solvent absorption or membrane and cryogenic separation. The CO₂ may then be compressed and dehydrated for export.

• • • 1. Overview

An example of an ATR process is illustrated in Figure D.3. An ATR production plant may be composed of the following sub-processes:

— A gas pretreatment plant, possibly including a sulphur removal unit (not shown)

— An autothermal reformer (optionally a pre reformer if the feed contains ethane, propane or other hydrocarbons of higher molecular weights) where the feedstock is reformed in Syngas composed of H₂ and CO. The main chemical reaction is CH₄ + H₂O → CO + 3 H₂

— A Water Gas Shift (WGS) reactor that converts CO in the syngas to carbon dioxide and H₂ via the following chemical reaction: CO + H₂O → CO₂ + H₂

— A Pressure Swing Adsorption unit (PSA) to purify the hydrogen

— A Carbon Capture Unit

For this ATR process, the co-products are carbon dioxide and steam. Steam may be used to produce electricity, if there is associated power generation, e.g. combined heat-power or cogeneration applications, or to provide heat for other applications outside of the plant boundary (e.g. other manufacturing sites in the vicinity of the ATR).

Figure D.3 — Example of a simplified ATR plant block diagram

• • 1. Emission sources and inventory

Sections D.2.2.1, D.2.2.2 and D.2.2.3 provide information on emission sources and inventory for hydrogen produced from autothermal reforming.

• • • 1. Emission sources [informative]

For ATR, the main source of GHG emissions is the combustion of fossil fuel to provide heat to convert methane into syngas and venting of CO₂ generated by the WGS reactor. Other emission sources may include

— Emissions associated with the production and transportation of process inputs (feedstock and energy);

— Emissions associated with purchased electricity for the operations illustrated in Figure D.1;

— Direct emissions of CO₂, methane, or other greenhouse gases at the hydrogen plant due to unmitigated combustion or venting

— Direct and indirect emissions associated with operation of CO₂ pipelines and facilities delivering CO₂ to permanent geological sequestration (CCS).

Each process unit or stage in the ATR process contains unique emissions sources as outlined in Table D.3.

Table D.3 — Potential GHG emission sources in the life cycle of hydrogen produced by ATR

• • • 1. Inventory in case of Attributional Approach
         1. Energy supply and upstream emissions:

GHG emissions associated with hydrogen plant third-party feedstocks, including natural gas, steam and electricity are evaluated based on 4.3.2.5.4, 4.3.2.5.3, 4.3.2.5.2 and Annex C.

• • • • 1. Direct emissions at production:

The quantity of CO₂ released into the atmosphere during the hydrogen production stage may be estimated using the carbon balance within the boundaries of the plant. The total carbon input is determined from the quantity and characteristic of the feedstock and fuel. The total carbon output is the sum of

— Carbon in the CO₂ emitted

— Carbon in the CO₂ captured (used or sequestered)

— Carbon in the CO produced and sold, if any, and

— Carbon in the hydrogen product (i.e. impurities)

— Emissions of other possible carbon-containing species emitted, such as methane, volatile organic compounds, and CO.

NOTE: Other GHG emissions, such as N₂O, shall be accounted for.

• • • • 1. Inventory in case of Consequential Approach

In case of a consequential approach, the inventory may include inventories associated with displaced/substituted co-products. The goal of the LCA will define the appropriate system boundaries beyond the hydrogen production system boundary which can account for GHG emissions or emissions reductions as a result of hydrogen production.

For instance, the inventory may include the emissions expected from conventional means to produce the co-products (substitution methods).

See Annex B for more details on consequential approaches to carbon foot printing.

• • 1. Emission Allocation

Several co-products may exist for an ATR with CCUS, including steam, CO, electricity, and CO₂. The specific co-products will depend on the design of the hydrogen plant.

• • • 1. Allocation: Attributional Approach [Normative]
         1. Partitioning

As described at 4.3.3, the first step for the emission allocation is to subdivide the process.

Process subdivision:

The ATR process illustrated in Figure D.4 may be subdivided into two sub-processes as illustrated in Figure D.4:

— Sub-process 1: The ATR reactor. This sub-process has natural gas or other hydrocarbons as well as process water as process inputs, and syngas and steam as co-products. Syngas is mainly composed of Hydrogen, CO, some traces of CO₂ and other impurities such as N₂ and unreacted methane.

— Sub-process 2: Water Gas Shift + Carbon Capture (optional): This sub-process has syngas and steam as inputs and hydrogen and CO₂ as outputs. In case of CCUS, CO₂ is considered a co-product (CCU) or a waste (CCS).

Figure D.4 — Example of a simplified ATR plant block diagram – subdivision in sub processes

Allocation

Sub-process 1 – ATR Reactor: Emissions associated with natural gas, oxygen, and other inputs to sub-process 1 as well as the direct emissions associated with sub-process 1are allocated to the syngas and steam co-products of sub-process 1 prorata their energy content (LHV^[11] or, in case of the steam, the enthalpy difference between steam and the steam condensate). The steam carbon footprint results from the allocation of the combustion emissions of the natural gas allocated to it.

All GHG emissions associated with syngas will be allocated to the products of sub process 2.

Sub-process 2 – Water Gas Shift

The direct emissions from sub-process 2 determined as described D.1.2.2.2 are added to the emissions associated with the syngas fed to Sub process 2 as well as direct and indirect emissions associated with transportation and sequestration of CO₂ placed in permanent geological storage (CCS).

• • • 1. Allocation: Consequential Approach [Informative]

Under a consequential approach, the allocation of emissions to co-products may be avoided by applying substitution / system expansion with displacement as described in 4.3.3.

If a hydrogen plant produces steam in addition to hydrogen, then the co-product steam shall be considered to displace steam of equivalent enthalpy (temperature, pressure, and quality) generated by combustion of fuel in a boiler. The (displaced) boiler efficiency shall be representative of the efficiency of boilers of equivalent size used to generate steam in the country where the hydrogen plant is located, or otherwise specified by governmental policy.

Expressed symbolically in Equation D.3.

(D.3)

In this equation,

— is the consequential “Raw Material Extraction to Production Gate” carbon footprint of hydrogen manufactured via the process illustrated in Figure D.3.

— (kgCO₂e) is the sum of all GHG emissions at the hydrogen plant illustrated Figure D.3.

— are the carbon footprints of inputs to the hydrogen plant illustrated in Figure D.3 (kgCO₂e/kg feedstock for material inputs and kgCO₂e/kWh for purchased electricity)

— are the flowrates of inputs to the hydrogen plant illustrated in Figure D.3. (kg/hr for material inputs and kW for purchased electricity),

— is the carbon footprint (raw material extraction through production) of steam displaced by the hydrogen plant illustrated in Figure D.3 (“Steam(heat)”)

— is the carbon footprint (raw material extraction through production) of CO₂ displaced by the hydrogen plant illustrated in Figure D.3 (“CO₂(CCU)”)

— is the sum of flowrates (kg/hr) of hydrogen produced by the hydrogen plant illustrated in Figure D.3

— is the flowrate (kg/hr) of steam displaced by the hydrogen plant illustrated in Figure D.3 (“Steam (heat)”)

— is the flowrate (kg/hr) of utilized carbon dioxide displaced by the hydrogen plant illustrated in Figure D.3 (“CO₂”)

If the hydrogen plant displaces steam generated by a natural gas boiler in the region of the hydrogen plant, then the CFP of in Figure D.3 may be calculated using Equation D.2 (D.1.3.2).

If the hydrogen plant displaces steam generated by a boiler using a different fuel, then the natural gas-specific terms in Equation D.2 should be replaced with those of the other fuel. The choice of fuel for steam generation may vary by region, and must be justified and disclosed explicitly to stakeholders. Carbon footprints of other fuels (e.g. coal or fuel oil) should be selected according to the criteria in Annex C.

Similarly, the CFP of CO₂ in Equation D.3 (displaced by CO₂ produced at the hydrogen plant) should be representative of CO₂ feedstocks in the region of the hydrogen plant. The source of CO₂ feedstocks may vary by region, and must be justified and disclosed explicitly to stakeholders.

• • 1. Information to be reported [Normative]

Table D.4 presents the information to be reported for hydrogen produced from autothermal reforming with carbon capture and storage.

Table D.4 — Potential GHG emission sources in the life cycle of hydrogen produced by ATR

1. 
   
   Hydrogen Production Pathway – Water Electrolysis
   1. Electrolysis [Informative]

There are currently three main electrolyser technologies, distinguished by the electrolyte (and associated production temperatures): alkaline, proton exchange membrane and solid oxide electrolysis cell. However, the methodology for emissions allocation presented in this annex may be applied to any electrolysis technology.

• • 1. Description

A water electrolysis cell consists of an anode and a cathode separated by a conductive electrolyte or ion transport medium. When connected to a direct current power supply, electricity flows through the electrolyte and causes the water to split into hydrogen and oxygen. Each electrolyser system consists of a stack of electrolysis units, a gas purifier, dryer and an apparatus for heat removal.

Hydrogen must be purified, dried and cooled prior to storage and/or delivery to market, subject to required product specifications. The oxygen gas must be safely vented to the atmosphere. Alternatively, this oxygen may be collected and sold as a co-product. In such a case, the oxygen gas product must be purified, dried and cooled prior to storage and/or delivery to market, subject to required product specifications.

• • 1. Overview

An example of a process diagram for hydrogen produced from electrolysis is presented in Figure E.1. System design layout may vary from one facility to another.

System inputs includes elementary flows (e.g., water, steam) and product flows (e.g., electricity, fuel, etc…). The system outputs are hydrogen, oxygen, and waste. If oxygen is being vented to the atmosphere, then it is considered waste and the only product of the system is hydrogen. If oxygen is being collected, then the system has both a product (hydrogen) and a co-product (oxygen).

Figure E.1 — Example of process diagram for hydrogen produced from electrolysis

• 1. Emission Sources and Inventory

This section details potential GHG emission inventory sources for hydrogen produced from electrolysis. It also discusses the inventory needed for the attributional approach and the consequential approach.

• • 1. Emission Sources [Informative]

Table E.1 lists typical emission sources classified by emissions categories.

GHG emissions associated with electrolysis are primarily dependent on the nature of energy supply for electrolysis.

Table E.1 — Potential GHG Emissions in the Life Cycle of Hydrogen Produced via Electrolysis

• • 1. Inventory in case of Attributional Approach [Normative]

The attributional approach will assign the inputs and outputs to potential GHG emissions of hydrogen based on the measured, forecasted, or historical production.

• • • 1. Upstream/ Indirect Emissions

Upstream/indirect emissions associated with electrolysis come from the energy supply purchased for the production (see 4.3.2.5).

• • • 1. Direct Emissions

If the energy supplied for the electrolysis, converted on-site, then any GHG released associated with the supplied energy is a direct emission. The quantity of GHG emissions should be estimated from energy supply calculations (4.3.2.5).

• • 1. Inventory in case of Consequential Approach [Informative]

In case of a consequential approach, the inventory may include inventories associated with displaced/substituted co-products. The goal of the LCA will define the appropriate system boundaries beyond the hydrogen production system boundary which can account for GHG emissions or emissions reductions as a result of hydrogen production.

For instance, the inventory may include the emissions expected from conventional means to produce the co-products (substitution methods).

See Annex B for more details on consequential approaches to carbon foot printing.

• 1. Emission Allocation

Emissions allocation is only necessary if the process being modelled is considered multifunctional. The water electrolysis process is only considered multifunctional if other outputs such as oxygen and heat become co-products. If oxygen and heat are released into the environment, then hydrogen is the only product and allocation is avoided.

• • 1. Attributional Approach [Normative]

With the attributional approach, allocation cannot be avoided in a multifunctional electrolysis system because the operation units cannot be further subdivided. It is analysed as a single module with one co-product (oxygen). There are four options for allocation:

1. Mass based allocation: in this case most of the emissions (almost 90 %) will be allocated to the oxygen, as the mass ratio for hydrogen to oxygen is 1:8.

2. Molar based allocation: In this case, approximately 2/3 of the emissions will be allocated to hydrogen.

3. Mass-enthalpy product-based allocation: in this case, approximately 65 % of the emissions will be allocated to hydrogen, according to Equations 1, 2 and 3:

(E.1)

(E.2)

(E.3)

Where:

— (kg feedstock j) is the mass input of the jth material feedstock (e.g. water) or externally supplied fuel to the electrolysis facility; the sum is taken over all feedstocks. Where applicable, the externally supplied fuels are used to generate steam and electricity on-site,

— (kgCO₂e/kg feedstock j) is the ”raw material extraction to production gate” carbon intensity associated with the jth material feedstock delivered to the facility,

— is the product of the amount of external (e.g. grid) electricity input (kWh) and the carbon footprint of the purchased electricity (kgCO₂e/kWh electricity delivered to the facility),

— S is the product of the amount of external (not internally-generated) steam input to the electrolyser (MJ) and the carbon footprint of the purchased steam (kgCO₂e/MJ steam delivered),

— D is the sum of the direct emissions associated with the on-site generation of steam or electricity (kg CO₂e). The brackets around the term D in equation E1 accounts for the on-site steam and/or power generation possibility,

— is the allocation factor for the co-product i,

— is the mass of the co-product i (kg of co-product i),

— is the specific enthalpy of co-product i (kJ/kg of co-product i), determined at the temperature and pressure of the stream i measured at the electrolyser corresponding outlet,

NOTE: the specific enthalpy may be determined from thermodynamic tables (e. g. https://webbook.nist.gov/chemistry/fluid/). In any case, the source used to determine the specific enthalpy should be indicated.

4. Economic value allocation: in this case, it is based on the market price of each co-product.

Heating value allocation is not appropriate for this process because oxygen is not a fuel. For this process, a molar based allocation method shall be applied.

• • 1. Consequential Approach [Informative]

With the consequential approach (i.e. system expansion), allocation can be avoided with system boundary expansion. Oxygen and excess heat generated from electrolysis could be used to substitute for an an alternative way of producing oxygen or generating heat. For example, oxygen produced in electrolysis can be used to replace oxygen production from cryogenic distillation systems – the most common process for producing oxygen. Emissions associated with the oxygen product stream can be estimated referring to relevant air separation model established within LCA databases or by LCA of oxygen production by cryogenic distillation system.

The counterfactual scenario represents the conventional practice and could vary by region and time as policy and incentives may change the value proposition.

• 1. Information to be Reported [Normative]

Table E.2 presents the information to be reported for hydrogen produced from electrolysis.

Table E.2 — Information to be reported for electrolysis

1. 
   
   Hydrogen Production Pathway – Chlor-alkali
   1. Process description and overview [Informative]
      1. Description

The chlor-alkali industry produces chlorine (Cl₂), sodium hydroxide (NaOH) and H₂ through the electrolysis of brine. Electrolysis technologies in chlor-alkali plants include mercury, diaphragm, and membrane. Mercury technology is the oldest while diaphragm and membrane technologies are becoming more prevalent.^[1] The key advantage of mercury technology is producing highly concentrated sodium hydroxide at 50 % with lower brine quality requirement, but with higher electricity consumption and adverse environmental impact. The advantages of diaphragm technology are lower electricity consumption for electrolysis and ability to handle lower quality of raw material but requires higher energy for concentrating co-product sodium hydroxide.^[1] A general representation of the chlor-alkali process is shown in Figure F.1 ^[2].

The electrolysis of brine (sodium chloride or potassium chloride KCl) produces Cl₂, NaOH (or potassium hydroxide [KOH]), and H₂ as follow:

2 NaCl + 2 H₂O → Cl₂ + H₂ + 2 NaOH

Chlorine and sodium hydroxide are the main products from electrolysis with 46,4 % and 52,3 % mass share, respectively, while hydrogen’s share is only 1,3 %. The hydrogen from chlor-alkali plants has high purity (>99 %).^[3] The co-produced hydrogen may be sold in the merchant market, used internally for its heating value, or vented as a waste stream.

Figure F.1 — An example of process diagram for hydrogen produced from chlor-alkali process

• • 1. Overview

Chlor-alkali plants vary by their final products, which includes hydrochloride (HCl), sodium hypochlorite (NaClO), ethylene dichloride (EDC), vinyl chloride monomer (VCM) as shown in Figure F.2. Given the variability of the chlor-alkali processes, system boundaries and final products, it is important to assign the energy use and emissions to the various products using appropriate allocation methods.

Figure F.2 — An example of the various possible products from chlor-alkali plant (adopted from Vyawahare et al) ^[2]

• 1. Emission sources and inventory

Table F.1 — GHG emissions summary for chlor-alkali pathway

• 1. Emission Allocation
     1. Emission inventory using Attributional Approach [Normative]

Using an attributional approach, the energy use and emission burdens associated with the chlor-alkali process are allocated to unit products (i.e., Cl₂, NaOH/KOH and hydrogen) by their physical attributes. Since Cl₂ and NaOH (or KOH) are not valorised by their energy, the physical attribute for emissions allocation among Cl₂, NaOH and hydrogen shall be by mass.

The formulas below provide an example of emissions allocation to product i among co-products of the chlor-alkali process by their mass shares. Similar formulas may be used for emissions allocation by shares of other relevant physical attributes of co-products. After proper allocation of process emissions to the hydrogen co-product, the additional emissions associated with drying, cooling and compression of hydrogen should be added to calculate the carbon footprint of hydrogen^[3].

(F.1)

In this expression,

(F.2)

In Equations F.1 and F.2

— is defined in Equation F.2, and is the sum of greenhouse gases associated with the feedstocks

— (kg feedstock j) is the mass input of the jth material feedstock (e.g., brine) or externally supplied fuel (e.g. natural gas) to the chlor-alkali process; the sum is taken over all feedstocks and externally supplied fuels that convert feedstocks into Cl₂, NaOH/KOH and H₂, but excludes other potential external inputs to the chlor-alkali process such as steam and electricity;

— (kgCO₂e/kg feedstock j) is the ”raw material extraction to production gate” carbon intensity associated with the jth material feedstock delivered to chlor-alkali process,

— P is the product of the amount of external (e.g. grid) electricity input to the chlor-alkali process (kWh) and the carbon footprint of the purchased electricity (kgCO₂e/kWh electricity delivered to the chlor-alkali process),

— D is the sum of the direct emissions associated with the chlor-alkali process (kgCO₂e),

— S is the product of the amount of external (not internally-generated) steam input to the chlor-alkali process (MJ) and the carbon footprint of the purchased steam (kgCO₂e/MJ steam delivered), and

— (kg) is the mass flow of the ith co-product leaving the chlor-alkali process to sale.

The formula below shall be used to allocate emissions by mass to co-product (i) in the chlor-alkali process.

(mass allocation) (F.3)

In Equation F.3 the denominator is the sum of masses of all co-products, assuming no excess electricity as a co-product (since electricity is not quantified in mass units).

Calculation of emissions credits using substitution via system expansion for facilities that export electricity and/or steam are explained in sections F.3.3 and F.3.4, respectively.

• • 1. Emission inventory using Consequential Approach [Informative]

In a consequential approach, other considerations associated with valorising hydrogen as a co-product can be accounted for. These include counterfactual scenarios for hydrogen use in a typical chlor-alkali plant, such as its internal use for heating and/or power generation, or venting it as a waste as mentioned in C.1.1. The counterfactual scenario represents the conventional practice in a given region and could vary by region and also with time as policy and incentives may change the value proposition of the hydrogen co-product.

In a counterfactual scenario where hydrogen is vented, the only relevant processes for emissions associated with co-product hydrogen are related to hydrogen post-processing shown in Figure C.2 (i.e., drying, cooling and compression), which are needed to valorise hydrogen for export. In this case, the environmental burden is not assigned to the chlor-alkali process.

A consequential approach accounts for changes to the chlor-alkali plant operation associated with valorising hydrogen as a co-product. The carbon footprint is defined as the difference in life cycle emissions between two scenarios.

i.e.

() (F.4)

In Equation F.4, is the amount of hydrogen produced (kg) in the “valorization scenario”, (kg CO₂e) is the sum of emissions from “raw material extraction to production gate” associated with the chlor-alkali plant operation when hydrogen is valorized, and (kg CO2e) is the sum of emissions from “raw material extraction to production gate” associated with the chlor-alkali plant operation when hydrogen is not valorized. The scenarios must be constrained so that the types and amounts of non-hydrogen co-products of the chlor-alkali operation – including energy co-products such as steam and electricity, are equal.

As an example, consider a chlor-alkali plant that produces a hydrogen co-products as discussed in C.1.1. A counterfactual scenario could be considered where hydrogen generated by chlor-alkali process becomes a component in the plant’s fuel gas system and is used for process heat. In the valorization scenario, the hydrogen is no longer used as fuel. Therefore, the chlor-alkali plant may require a substitute fuel input (e.g., natural gas). Moreover, in the valorization scenario, additional electricity may be required to cool hydrogen and compress the hydrogen co-product. If for example (a) the chlor-alkali plant uses the same amount of feedstocks and yields the same flows of co-products except hydrogen, including steam, and electricity, and (b) an additional kWh of external electricity are required for hydrogen cooling and compression in the valorization scenario, then

(F.5)

Here, is the sum of direct emissions of the chlor-alkali plant that valorizes hydrogen as a product (kg CO₂e) and is the sum of direct emissions of the chlor-alkali plant that utilizes hydrogen as fuel (kg CO₂e). The quantity is the mass of supplemental natural gas (i.e., substituting for energy in exported hydrogen) multiplied by its lower heating value (LHV), and is the “raw material extraction to production gate” carbon footprint of the supplemental natural gas fuel delivered to the chlor-alkali plant in the valorization scenario; emissions associated with its combustion are accounted in .

• • • 1. Facility credit with electricity export

Some chlor-alkali plants may generate electricity on-site via combined heat and power (CHP) processes instead of purchasing electricity from the grid. These plants may generate a surplus of electricity that is exported to the grid after satisfying onsite electricity demand. In this case, the magnitude of the quantity P in Equation F.1 becomes negative, reflecting the fact that grid electricity is displaced, not consumed. In such case, the electricity displacement credit is accounted for before applying the allocation method as described in F.3.2 above for other co-products.

• • • 1. Facility credit with steam export

Some chlor-alkali plants may generate steam as a co-product after satisfying onsite steam demand. In this case, the magnitude of the term S in Equation F.1 becomes negative, i.e., a credit is provided for displacing emissions associated with the generation of steam via combustion of conventional fuel (e.g., natural gas) in a boiler.

In this case, S shall be calculated as follows:

(kg CO2e) (F.6)

In Equation F.6,

— (kg) is the amount of steam exported from the chlor-alkali plant,

— (kJ/kg steam) is the "specific enthalpy change" (kJ/kg) defined by the difference in two thermodynamic states of steam at (a) the temperature and pressure of steam exiting the chlor-alkali plant, and (b) state of water at ambient temperature and pressure.

— is the LHV efficiency of a conventional boiler (e.g., natural gas) representative of the region in which the chlor-alkali plant resides, or otherwise specified.

— (kgCO₂e/MJ, LHV basis) is the “raw material extraction to production gate” carbon footprint of conventional boiler fuel (e.g., natural gas) delivered to the chlor-alkali plant.

— (kgCO₂e/MJ, LHV basis) are the emissions associated with the combustion of conventional boiler fuel (e.g., natural gas) in a boiler.

The displacement credit should be accounted for before applying the allocation method described in F.3.2 above for other co-products.

• 1. Information to be reported [Normative]

Table F.2 — Information to be reported for hydrogen production from chlor-alkali process

1. 
   
   Hydrogen Production Pathway – Steam cracking
   1. Process description and overview [Informative]
      1. Description

Steam cracking is a petrochemical process in which saturated hydrocarbons are broken down into smaller, typically unsaturated, hydrocarbons. It is the principal industrial method for producing the lighter alkenes (or commonly olefins), including ethene (or ethylene) and propene (or propylene). Steam cracker units are facilities in which feedstocks such as naphtha, liquefied petroleum gas (LPG), ethane, propane and butane are thermally cracked in the presence of steam in cracking furnaces to produce olefins. Propane dehydrogenation may be accomplished through alternative commercial technologies. Differences between alternative cracking technologies include the catalyst employed, design of the reactor and strategies to achieve higher conversion rates.

Olefins are useful precursors to many products. Steam cracking is the core technology that supports the largest scale chemical manufacture of olefins. Ethane, propane and butane (often originating from natural gas liquids (NGLs)) and naphtha from petroleum refineries are the dominant feedstocks for steam crackers.^[1] When ethane is cracked the hydrogen co-product is approximately 4 % by mass^[2].

Process description of co-product hydrogen from steam cracking of naphtha or other feedstocks:

— Steam cracking of naphtha yields a variety of olefins, which are predominantly used as feedstocks for polymer manufacture. First, naphtha is pre-heated to temperatures of 550-600 °C and mixed with steam at temperatures of 180-200 °C. Then, the mixture is heated to a temperature of 800-850 °C, at which the hydrocarbons are cracked into ethylene, propylene and other olefins, among other co-products, including hydrogen. The heating and cracking processes are typically heat-integrated to increase the process efficiency.

— The hydrogen produced by steam cracking of naphtha or other feedstocks may be used as fuel, sold, or both. For instance, a portion of the hydrogen may be used as part of the fuel gas for the furnace, another portion may serve as a source of fuel gas to fire a boiler,^[3] and another portion may be separated and purified (e.g., via pressure swing adsorption) and compressed for sale to customers.

— Steam cracking of ethane and other natural gas liquids is similar to the naphtha cracking process, but the volumes and types of olefins resulting from the process differ. Separation and purification processes may be less extensive if butanes, butenes and larger paraffins and olefins are not present in the steam cracker effluent.

• • 1. Overview

Figure G.1 — An example of process diagram for hydrogen produced from steam cracking

• 1. Emission sources and inventory
     1. Emission sources

Greenhouse gas (GHG) emissions from steam cracking are related to the combustion of fuel gas generated from the cracking process, which is used to provide the required heat to the process. Combustion occurs at the furnace and boilers). The emissions associated with steam cracking furnaces depend on the fuel used in the furnaces, which may vary due to the steam cracking process (ethane, propane, butane, naphtha, or other forms of cracking).

• • 1. Emission inventory

Table G.1 — GHG emissions summary for steam cracking pathway

• 1. Emission Allocation
     1. Emission inventory using Attributional Approach [Normative]

Using an attributional approach, the energy use and emission burdens associated with the steam cracking process are allocated to unit products (i.e., olefin products and hydrogen) by their physical attributes. Mass allocation shall be used for the co-products. The appropriate physical attribute for emissions allocation may be decided by how the co-products are valorised. The formulas below provide an example of emissions allocation to product i among co-products by their mass shares. After proper allocation of process emissions to the hydrogen co-product, the additional emissions associated with purification and compression of hydrogen should be added to calculate the carbon footprint of the produced hydrogen (Equations G.1 and G.2).

(G.1)

In this expression,

, (G.2)

In Equations G.1 and G.2

— is defined in Equation G.2, and is the sum of greenhouse gases associated with the feedstocks

— (kg feedstock j) is the mass input of the jth material feedstock (e.g. naphtha) or externally supplied fuel (e.g. natural gas) to the steam cracker; the sum is taken over all feedstocks and externally supplied fuels that convert feedstocks into olefins, but excludes other potential external inputs to the steam cracking process such as steam and electricity;

— (kg CO₂e/kg feedstock j) is the ”raw material extraction to production gate”carbon intensity associated with the jth material feedstock delivered to steam cracker,

— P is the product of the amount of external (e.g. grid) electricity input to the steam cracking plant (kWh) and the carbon footprint of the purchased electricity (kg CO₂e/kWh electricity delivered to the steam cracker),

— D is the sum of the direct emissions associated with the steam cracker plant operation (kg CO₂e),

— S is the product of the amount of external^[12] (not internally-generated) steam input to the steam cracking plant (MJ) and the carbon footprint of the purchased steam (kg CO₂e/MJ steam delivered), and

— (kg) is the mass flow of the ith co-product leaving the steam cracking plant to sale.

Equation G.3 shall be used to allocate emissions by mass to co-product (i) in the steam-cracking process.

(mass allocation) (G.3)

In Equation G.3 the denominator is the sum of masses of all co-products, assuming no excess electricity as a co-product (since electricity is not quantified in mass units).

Calculation of emissions credits using substitution via system expansion for facilities that export electricity and/or steam are explained in sections G.3.2.1 and G.3.2.2, respectively.

• • 1. Emission inventory using Consequential Approach [Informative]

A consequential approach accounts for changes to the steam cracking plant operation associated with valorising hydrogen as a co-product. The carbon footprint is defined as by difference in life cycle emissions between two scenarios^[2].

i.e., Equation G.4:

() (G.4)

In Equation G.4, is the amount of hydrogen produced (kg) in the “valorization scenario”, (kg CO2e) is the sum of emissions from ”raw material extraction to production gate” associated with the steam cracker when hydrogen is valorized, and (kg CO2e) is the sum of emissions from ”raw material extraction to production gate” associated with the steam cracker when hydrogen is not valorized. The scenarios must be constrained so that the types and amounts of non-hydrogen co-products of the steam cracker – including energy co-products such as steam and electricity, are equal.

As an example, consider a steam cracker that produces a hydrogen co-product as discussed in G.1.2. A counterfactual scenario could be considered where hydrogen generated by steam cracking becomes a component in the steam cracker plant’s fuel gas system and is used for process heat. In the valorization scenario, the hydrogen is no longer used as fuel. Therefore, the steam cracker facility may require a substitute fuel input (e.g., natural gas). Moreover, in the valorization scenario, additional electricity may be required to separate hydrogen from other cracker process gases and to compress the purified hydrogen co-product. If for example (a) the steam cracking facility uses the same amount of feedstocks and yields the same flows of co-products except hydrogen, including steam, and electricity, and (b) an additional kWh of external electricity are required for hydrogen purification and compression in the valorization scenario, then, according to Equation G.5:

(G.5)

Here, is the sum of direct emissions of the steam cracker facility that valorizes hydrogen as a product (kg CO₂e) and is the sum of direct emissions of the steam cracker facility that utilizes hydrogen as fuel (kg CO₂e). The quantity is the mass of supplemental natural gas (i.e., substituting for energy in exported hydrogen) multiplied by its lower heating value (LHV), and is the “raw material extraction to production gate” carbon footprint of the supplemental natural gas fuel delivered to the steam cracker in the valorization scenario; emissions associated with its combustion are accounted in .

• • • 1. Facility credit with electricity export

Some steam cracking plants may generate electricity on-site via combined heat and power (CHP) processes instead of purchasing electricity from the grid. These plants may generate a surplus of electricity that is exported to the grid after satisfying onsite electricity demand. In this case, the magnitude of the quantity P in Equation G.1 becomes negative, reflecting the fact that grid electricity is displaced, not consumed. In such case, the electricity displacement credit is accounted for before applying the allocation method as described in G.3.2 above for other co-products.

• • • 1. Facility credit with steam export

Some steam cracking plants may generate steam as a co-product after satisfying onsite steam demand. In this case, the magnitude of the term S in Equation G.1 becomes negative, i.e., a credit is provided for displacing emissions associated with the generation of steam via combustion of conventional fuel (e.g., natural gas) in a boiler.

In this case, S shall be calculated according to Equation G.6:

   (kg CO2e) (G.6)

In Equation G.7,

— (kg) is the amount of steam exported from the steam cracker facility,

— (kJ/kg steam) is the "specific enthalpy change" (kJ/kg) defined by the difference in two thermodynamic states of steam at (a) the temperature and pressure of steam exiting the steam cracker facility, and (b) state of water at ambient temperature and pressure.

— is the LHV efficiency of a conventional boiler (e.g., natural gas) representative of the region in which the steam cracker facility resides, or otherwise specified.

— (kg CO₂e/MJ, LHV basis) is the raw material extraction to production gate carbon footprint of conventional boiler fuel (e.g., natural gas) delivered to the steam cracker facility.

— (kg CO₂e/MJ, LHV basis) are the emissions associated with the combustion of conventional boiler fuel (e.g., natural gas) in a boiler.

The displacement credit should be accounted for before applying the allocation method described in G.3.2 above for other co-products.

• 1. Information to be reported [Normative]

Table G.2 — Information to Be Reported for Hydrogen co-product from steam cracking

1. 
   
   Hydrogen Production Pathway – Gasification with or without carbon capture
   1. Overview [Informative]

This annex describes the hydrogen production pathway - gasification (with carbon capture and storage). The types of gasification include coal gasification, biogenic waste gasification, and non-biogenic waste gasification. The definitions of the following words and phrases in this Annex are given in 3.3.

— Waste (3.3.15 and Annex C)

— Biogenic waste (3.3.16)

— Non-biogenic waste (3.3.17)

In addition, the system boundary setting is described in Annex C.

• 1. Gasification (with or without carbon capture)
     1. Process description and overview [informative]

Sections H.1.1.1 and H.1.1.2 provide a description and an overview for hydrogen produced from gasification with carbon capture and storage.

• • • 1. Description

Gasification is a typical technology for producing hydrogen from mainly solid feedstock such as coal, biogenic waste, and non-biogenic waste.

To produce hydrogen gas, the feedstock is pyrolyzed and gasifired with oxygen, steam and carbon dioxide in a reactor (a gasifier). The gasification global reactions are displayed in Equations H.1 to H.4:

C_xH_yO_z(Feedstock) + heat →CO + CO₂ + H₂O + HCs +C(char, carbon) (H.1)

C + 1/2O₂ → CO + heat (H.2)

C + H ₂ O (steam) + heat → CO + H₂ (H.3)

C + CO₂ + heat → 2CO (H.4)

The reaction takes place at high temperatures and some of the char and hydrocarbons (including tar) are oxidised by the oxygen to generate heat is displayed in Equation H.5:

C + O₂ → CO₂ + heat (H.5)

A Gasification plant is typically composed of the following units and systems:

— A Pretreatment system where a solid feedstock undergoes processes such as drying, pulverizing, sorting, crushing, and molding to meet the feedstock requirements of the gasifier

— A Gasifier

— A Waste heat recovery unit that exchanges heat with the syngas to produce steam.

— A Water-Gas Shift (WGS) reactor that converts CO and steam in the syngas to carbon dioxide and hydrogen via the following chemical reaction in Equation H.6:

CO + H₂O → CO₂ + H₂ (H.6)

The Gas treatment system that removes sulfur compounds (such as H₂S) and heavy metals (such as mercury)

— A Hydrogen compression^[13] and/or A Pressure Swing Adsorption unit (PSA)^[14], depends on the hydrogen pressure and purity corresponding to the inlet requirements of the subsequent stages.

— A Carbon Capture Unit (optional)

• • • 1. Overview

An example of a process diagram for hydrogen production from gasification with carbon capture is presented in Figure H.1.

Figure H.1 — Example of a specific gasification plant block diagram

• • 1. Emission sources and inventory

Sections H.1.2.1, H.1.2.2 and H.1.2.3 provide the emissions sources and inventory in case of attributional approach and consequential approach for hydrogen produced from gasification with carbon capture and storage.

• • • 1. Emission sources[informative]

For gasification with CCS, the main source of GHG emissions is the conversion of carbon in feedstock to syngas and the CO₂ resulting from the conversion of CO and steam to hydrogen and CO₂. Other emission sources include

— Emissions associated with the production and transportation of process inputs (feedstock and energy);

— Emissions associated with purchased electricity for the operations illustrated in Figure H.1;

— Indirect emissions associated with operation of CO₂ pipelines and facilities delivering CO₂ to permanent geological sequestration (CCS).

Emissions sources of each process unit or stage in the Gasification process are outlined in Table H.1.

Table H.1 — Potential GHG Emissions in the Life Cycle of Hydrogen Produced via Gasification

• • • 1. Inventory in case of Attributional Approach [normative]
         1. Energy supply and upstream emissions:

GHG emissions associated with hydrogen plant third-party feedstocks, including natural gas, steam and electricity are evaluated based on 4.3.2.5.4, 4.3.2.5.3, 4.3.2.5.2 and Annex C.

• • • • 1. Direct emissions at production

The quantity of CO₂ released into the atmosphere during the hydrogen production stage may be estimated using the carbon balance within the boundaries of the plant, although measured values are preferred. The total carbon input is determined from the quantity and characteristic of the feedstock and fuel. The total carbon output is the sum of

— Carbon in the CO₂ emitted

— Carbon in the CO₂ captured (used or sequestered)

— Carbon in the CO produced, if any, and

— Carbon in the hydrogen product (i.e. impurities)

— Emissions of other possible carbon-containing species emitted, such as methane, volatile organic compounds (VOC), and CO.

— Carbon in any solid waste/stream.

NOTE: Other GHG emissions, such as N₂O, shall be accounted for.

• • • 1. Inventory in case of Consequential Approach [informative]

In case of a consequential approach, the inventory may include inventories associated with displaced/substituted co-products. The goal of the LCA will define the appropriate system boundaries beyond the hydrogen production system boundary which can account for GHG emissions or emissions reductions as a result of hydrogen production. For instance, the inventory may include:

— the emissions expected from other means to produce the co-products (substitution methods).

— the emissions expected from the use of co-products (e.g., CO or CO2)

— the associated emissions from combusting waste feedstocks in the counterfactual scenario as avoided burden instead of converting and using a waste feedstock in hydrogen production (see Annex C) (adapted from (Jeswani et al., 2021^[1]; Daigo et al., 2023^[2]; EC,2023^[3]; UK, 2023^[4]; EC IF, 2023^[5])).

See Annex B for more details on consequential approaches to carbon foot printing.

• • 1. Emission Allocation

Several co-products may exist for a gasification with CCUS, including steam and CO₂ (in case of CCU). The specific co-products will depend on the design of the hydrogen plant.

• • • 1. Allocation: Attributional Approach [normative]

With the attributional approach, allocation cannot be avoided in a multifunctional gasification system because the operation units cannot be further subdivided. The gasification system includes a range of potential co-products, including steam via waste heat recovery and CO₂ sold as a product. The scale of production for these potential co-products remain uncertain and is likely subject to facility-specific commercial circumstances (i.e. energy costs, grid considerations, plant design and operation). The direct and indirect emissions associated with transportation and sequestration of CO₂ placed in permanent geological storage (CCS) must be added. The sum of these emissions is allocated to hydrogen, steam and CO₂ sold as a product (“CO₂ (CCU)”). Allocation methods follow 4.3.2.2.

• • • 1. Allocation: Consequential approach [Informative]

Under a consequential approach, emission allocation to co-products may be avoided by applying substitution / system expansion with displacement as described in 4.3.3.

If a hydrogen plant produces steam in addition to hydrogen, then the steam co-product shall be assumed to displace steam of equivalent enthalpy (temperature, pressure, and quality) generated by others means such as combustion of fuel in a boiler. The (displaced) boiler efficiency shall be representative of the efficiency of boilers of equivalent size used to generate steam in the country where the hydrogen plant is located, or otherwise specified by governmental policy. Expressed symbolically in Equation H.7,

(H.7)

In this equation,

— CFP_Hydrogen is the consequential “Raw material extraction to Production gate” carbon footprint of hydrogen manufactured via the process illustrated in Figure H.1.

— κ (kg CO2e) is the sum of all GHG emissions at the hydrogen plant illustrated in Figure H.1,

— {CFPi} are the carbon footprints of inputs to the hydrogen plant illustrated in Figure H.1 (kgCO₂e/kg feedstock for material inputs and kgCO₂e/kWh for purchased electricity)

— {f_i} are the flowrates of inputs to the hydrogen plant illustrated in Figure H.1(kg/hr for material inputs and kW for purchased electricity),

— CFP_steamis the carbon footprint (raw material extraction through production) of steam displaced by the hydrogen plant illustrated in Figure H.1 (“Steam”)

— f_Hydrogen is the sum of flowrates (kg/hr) of hydrogen produced by the hydrogen plant illustrated in Figure H.1

— If the hydrogen plant displaces steam generated by a natural gas boiler in the region of the hydrogen plant, then the CFP of in Equation H.5 may be calculated as follows:

(H.8)

where:

— CFP_NG is the carbon footprint of natural gas (kgCO₂e/kg NG),

— E_NG is the emission factor for natural gas combustion (kgCO₂e/kg NG),

— LHV_NG is the LHV of natural gas (kJ/kg natural gas)

— ε_boiler,NG is the LHV efficiency of the displaced natural gas boiler. And

— Δh_steam is the specific enthalpy difference between steam at export conditions (temperature, pressure, quality) and water at plant feed condition (kJ/kg steam)

If the hydrogen plant displaces steam generated by a boiler using a different fuel in the counterfactual scenario, then the natural gas-specific terms in Equation H.2 should be replaced with those of the other fuel. The choice of fuel for steam generation may vary by region, and must be justified and disclosed explicitly to stakeholders. Carbon footprints of other fuels (e.g. coal or fuel oil) should be selected according to the criteria in Annex C.

Similarly, the CFPs of N₂ and Ar in Equation H.7 (displaced by N₂ and Ar produced at the hydrogen plant) should be representative of N₂ and Ar feedstocks in the region of the hydrogen plant.

• • 1. Information to be reported [Normative]

Table H.2 shows the information to be reported for hydrogen produced from gasification with carbon capture and storage.

Table H.2 — Information to Be Reported for Gasification Pathway

1. 
   
   Hydrogen Production Pathway – Methane pyrolysis
   1. Methane pyrolysis
      1. Methane pyrolysis process description and overview [informative]

Sections I.1.1.1 and I.1.1.2 provide a description and an overview for hydrogen produced from methane pyrolysis.

• • • 1. Description

Methane pyrolysis (also referred to as methane splitting) is the thermal decomposition of methane, in the absence of oxygen, into its components: hydrogen and solid carbon.

The main chemical reaction is CH₄ → 2H₂ + C.

A methane pyrolysis plant typically contains the following sub processes:

— A reactor

— A heater

— A gas filtration unit to separate the hydrogen and solid carbon

— Hydrogen purification

— Hydrogen compression

For every kilogram of hydrogen, approximately 3 kg of solid carbon is produced. Depending on the methane pyrolysis process, it may also produce steam. CO₂ may be captured from processes in the system boundary.

• • • 1. Overview

The main simplified block flow diagram of a methane pyrolysis plant process is shown in Figure I.1.

Figure I.1 — Example of process diagram of a methane pyrolysis plant

• • 1. Emission sources and inventory

Sections I.2.1, I.2.2 and I.2.3 provide the emissions sources and inventory in case of attributional approach and consequential approach for hydrogen produced from methane pyrolysis.

• • • 1. Emission sources [informative]

Table I.1 lists typical emission sources, classified by emissions categories, for each input and subsystem of a methane pyrolysis process.

GHG emissions from the methane pyrolysis process include upstream emissions occurring during the life cycle related to the supply of inputs (feedstock and energy). Other significant emission sources may include emissions from the reaction process and via electricity or the combustion of hydrocarbon fuel to provide reaction heat and emissions related to CH₄ leaks.

Table I.1 — Potential GHG emissions in the lifecycle of hydrogen produced via Methane Pyrolysis

• • • 1. Inventory in case of Attributional Approach [normative]
         1. Energy supply and upstream emissions

GHG emissions associated with hydrogen plant feedstocks including natural gas, biomethane, water and electricity are evaluated based on 4.3.2.5.4, 4.3.2.5.2, 4.3.2.6 and Annex C.

• • • • 1. Direct emissions at production

If a hydrocarbon fuel is combusted to provide process heat, the quantity of CO₂ released into the atmosphere during the hydrogen production stage may be estimated using the carbon balance within the boundaries of the plant. The total carbon input is determined from the quantity and characteristic of the fuel. The total carbon output is the sum of

— Carbon in the CO₂ emitted (measured)

— Carbon in CO₂ captured (used or sequestered)Carbon in the solid product and

— Carbon in the hydrogen product (i.e. impurities)

• • • 1. Inventory in case of Consequential Approach [informative]

In case of a consequential approach, the inventory may include inventories associated with displaced/substituted co-products. The goal will define the appropriate system boundaries beyond the hydrogen production system boundary which can account for GHG emissions or emissions reductions as a result of hydrogen production. For instance, the inventory may include:

— the emissions resulting from other means to produce the co-products (substitution methods).

— The emissions expected from the use of co-products (e.g., solid carbon)_.

See Annex B for more details on consequential approaches to carbon footprinting.

• • 1. Emission Allocation

Several co-products may exist for a methane pyrolysis plant including steam and solid carbon. The specific co-products will depend on the design of the hydrogen plant.

• • • 1. Allocation: Attributional Approach [normative]

With the attributional approach, the methane pyrolysis system cannot be subdivided. As described in 4.3.3, where allocation cannot be avoided, it is done in a way that reflects the underlying physical relationships between the co-products.

Equations I.1 and I.2 illustrate how to calculate the CFP of co-product (i).

(I.1)

In this expression,

(I.2)

In equation I.1 and I.2,

— is defined in Equation I.2, and is the sum of greenhouse gases associated with the feedstocks,

— (kg feedstock j) is the mass input of the jth material feedstock (e.g. natural gas); the sum is taken over all material inputs (i.e. it excludes electricity),

— (kgCO₂e/kg feedstock j) is the “Raw materials extraction-to- production gate” carbon intensity associated with the jth material feedstock delivered to the methane pyrolysis process,

— P is the product of the amount of external (e.g. grid) electricity input to methane pyrolysis process (kWh) and the carbon footprint of the electricity employed for the methane pyrolysis process (kgCO₂e/kWh electricity delivered). If the electricity is sourced from the grid, then the carbon footprint of the purchased electricity shall be estimated in accordance with 4.3.2.5.2. If the electricity is generated at the plant, then its carbon footprint shall be assessed in accordance with ISO 14067,

— D is the sum of the direct emissions associated with the methane pyrolysis process, if applicable (kg CO₂e),

— D_CCS is the emissions associated with CO₂ captured and permanently stored, which includes direct and indirect emissions associated with capture, transportation and sequestration of CO_2, subtracted from the total CO₂ captured and permanently stored,

— (kg) is the mass flow of the ith co-product leaving the methane pyrolysis plant to sale.

The allocation factor for the ith product is and may be calculated according to Equation I.3:

(I.3)

For this process, mass allocation shall be used.

Where the methane is of biogenic origin^[15], refer to annex C..

• • • 1. Allocation: Consequential Approach [Informative]

Under a consequential approach, the allocation of emission to co-products may be avoided by applying substitution / system expansion with displacement as provided for in 4.3.3.

If a methane pyrolysis plant produces steam in addition to hydrogen, then the co-product steam shall be considered to displace steam of equivalent enthalpy (temperature, pressure, and quality) generated by combustion of fuel in a boiler. The (displaced) boiler efficiency shall be representative of the efficiency of boilers of equivalent size used to generate steam in the country where the hydrogen plant is located, or otherwise specified by governmental policy

If the solid carbon produced at a methane pyrolysis plant is valorized, the co-product solid carbon shall be considered to displace an equivalent product from a conventional process. . The substitute system of the displaced carbon should be defined.

Revise the statement to, “The co-product solid carbon shall be considered to displace either the same carbon allotrope or substituting material used in the same application”

Expressed symbolically in Equation I.4.

(I.4)

In this equation,

— CFP_Hydrogen is the consequential “Raw materials extraction to production gate” carbon footprint of hydrogen manufactured via the process illustrated in Figure I.1.

— κ (kg CO₂e) is the sum of all GHG emissions at the hydrogen plant illustrated in Figure I.1.

— {CFP_i} are the carbon footprints of inputs to the hydrogen plant illustrated in Figure I.1 (kgCO₂e/kg feedstock for material inputs and kgCO₂e/kWh for purchased electricity)

— {f_i} are the flowrates of inputs to the hydrogen plant illustrated in Figure I.1. (kg/hr for material inputs and kW for purchased electricity),

— CFP_C is the carbon footprint (raw material extraction through production) of C (solid carbon) displaced by the hydrogen plant illustrated in Figure I.1 (“C”)

— f_c is the flowrate (kg/hr) of solid carbon displaced by the hydrogen plant illustrated in Figure I.1

— CFP_steam is the carbon footprint (raw material extraction through production) of steam displaced by the hydrogen plant illustrated in Figure I.1 (“Steam”), if applicable

— f_steam is the flowrate (kg/hr) of steam displaced by the hydrogen plant illustrated in Figure I.1 (“Steam”) if applicable

— CFP_CO2 is the carbon footprint (raw material extraction through production) of CO₂ displaced by the hydrogen plant illustrated in figure I.1 (“CO₂ (CCU)”) if applicable

— f_CO2 is the flowrate (kg/hr) of utilized carbon dioxide displaced by the hydrogen plant illustrated in Figure I.1 (“CO₂ (CCU)”) if applicable

— f_Hydrogen is the sum of flowrates (kg/hr) of hydrogen produced by the hydrogen plant illustrated in Figure I.1 (“Hydrogen”)

If the hydrogen plant displaces steam generated by a natural gas boiler in the region of the hydrogen plant, then the CFP of the steam in Equation I.3 may be calculated according to equation I.5, as follows:

(I.5)

Here,

— CFP_NG is the carbon footprint of natural gas (kgCO2e/kg NG),

— e_NG is the emission factor for natural gas combustion (kgCO2e/kg NG),

— LHV_NG is the LHV of natural gas (kJ/kg natural gas)

— is the specific enthalpy difference between steam at export conditions (temperature, pressure, quality) and water at plant feed condition (kJ/kg steam)

If the hydrogen plant displaces steam generated by a boiler using a different fuel, then the natural gas-specific terms in Equation I.4 should be replaced with those of the other fuel. The choice of fuel for steam generation may vary by region and must be justified and disclosed explicitly to stakeholders. Carbon footprints of other fuels (e.g. coal or fuel oil) should be selected according to the criteria in Annex C. Similarly, the CFP of C in Figure I.1 (displaced by C produced at the hydrogen plant) should be representative of C feedstocks or substituting material in the region of the hydrogen plant. The source of C feedstocks may vary by region and must be justified and disclosed explicitly to stakeholders.

• • 1. Information to be reported [normative]

Table I.2 - presents the information to be reported for hydrogen produced from methane pyrolysis.

Table I.2 — Information to be reported for hydrogen production by methane pyrolysis

1. 
   
   Hydrogen Production Pathway – Chemical Looping Water Splitting with or without carbon capture
   1. CLWS/CCS Description [Informative]

A Chemical Looping Water Splitting (CLWS) system produces and separates hydrogen and carbon dioxide (CO₂) from Water and hydrocarbon-based fuels such as Natural Gas, Crude Oil, and Coal using Metal materials in one process. The CLWS system consists of a steam reactor, an air reactor, and a fuel reactor. In each reactor, reactants (steam, air, fuel) react with metal materials to produce hydrogen, carbon dioxide and heat, respectively. Therefore, the CLWS system produces high-purity hydrogen through water splitting (decomposition) without additional hydrogen purification unit such as PSA (pressure swing adsorption) and produces high-purity CO₂ without CO₂ capture system using material such as MEA absorbent. In addition, the CLWS system is operated autothermal without extra a combustor, it is minimizing emissions of CO₂ from other units.

CLWS production system is typically composed of the following sub processes.

— A gas pre-treatment / Sulfur removal unit

— A CLWS (optionally a Reformer/a Gasifier if the feed has a high hydrocarbon content) which consists of two or more reactors. In the steam reactor, steam is converted to hydrogen using metal as an oxidant. In the air reactor, oxygen reacts with metal to generate heat. In the fuel reactor, the hydrocarbon feedstock is converted to CO2 and steam using a metal reductant. The main chemical Reactions are according to Equations J.1 to J.3:

Steam Reactor: H₂O + Me (Metal) → H₂ + MeO(Metal Oxide) (J.1)

Air Reactor: Air + Me (Metal) → N₂ + MeO(Metal Oxide) + Heat (J.2)

Fuel Reactor: CH₄ + 4MeO (Metal Oxide) → CO₂ + 2H₂O + 4Me(Metal) (J.3)

— A Waste Heat Recovery Unit where heat of emission gases from Hydrogen / Air / Fuel reactors generates steam, heat and electricity for utility of CLWS system.

— A Pressure Swing Adsorption unit (PSA) to purify the hydrogen (optional)

— A CO2 Compression Unit (optional)

In the steam reactor of CLWS system, high-purity (above 99 %) hydrogen is produced which can be further purified by a hydrogen purification unit. The heat and steam used for the CLWS system are produced from the air and fuel reactor, respectively. Therefore, most of the CO₂ emitted from CLWS is emitted from the outlet gas of the fuel reactor. Since most of the outlet gas of the fuel reactor consists of CO₂ and H₂O, CO₂ is captured with high purity through exhaust gas cooling, compression, and liquefaction facilities. The CO₂ capture rate is approximately 80-95 %.

The main simplified block flow diagram for a CLWS is described in in Figure J.1.

Figure J.1 — Example of a simplified CLWS plant block diagram

• 1. Emission Sources in CLWS

For chemical looping water splitting (CLWS), the main source of GHG emissions is the oxidation of fossil fuel to reduce the metal oxide in the fuel reactor. Fossil fuels are converted into CO₂ and steam via pure O₂ combustion, where they react with metal oxides. Other significant emission sources include upstream emissions during the life cycle related to the supply of inputs (feedstock, such as natural gas, oil, coal, and energy), including emissions of grid electricity, CO₂ removal, and CO₂ compression for CCS.

The emission sources for each process unit or stage in the CLWS are listed in Table J.1.

Table J.1 — Key life cycle GHG emission sources in hydrogen production for CLWS

• 1. Emission inventory
     1. Inventory in case of Attributional Approach [Normative]

Emission inventory was performed across life-cycle stages.

Energy supply and upstream emissions:

GHG emissions associated with hydrogen plant third-party feedstocks, including natural gas, steam and electricity are evaluated based on 4.3.2.5.4, 4.3.2.5.3, 4.3.2.5.2 and Annex C.

Direct emissions at production:

The quantity of CO₂ released into the atmosphere during the production stage is determined by the carbon balance within the plant boundaries. The total carbon input was determined based on the feedstock quantity and characteristics, corresponding to the total carbon output, which is the sum of the carbon in the CO₂ emitted + carbon in the non-emitted CO₂ (used or stored) + carbon in the produced CO.

Emissions from capital goods:

As per Article 4.2.1, the quantification of CAPEX emissions should be provided. However, such emissions are expected to be less than 1 % of the total inventory, which is below most of the cut-off criteria.

• • 1. Inventory in case of Consequential Approach [Informative]

In the case of a consequential approach, inventory may be performed across life-cycle stages, extending beyond the production unit. The goal of LCA is to precisely define the boundaries considered in consequential emissions. For instance, LCA may include the following:

— emissions from other means of producing co-products (substitution methods).

• 1. Emission Allocation for the CLWS Pathway

Several co-products may exist in CLWS systems, including hydrogen, steam, electricity, and CO₂, depending on the specific plant designs.

• • 1. Allocation in case of Attributional Approach [Normative]

As described in Section 4.3.3, the first step in emission allocation is to subdivide the process.

— 1^st Step: Process subdivision

The unit process is subdivided into two subprocesses:

— Subprocess 1: CLWS

This subprocess uses steam as the input of the steam reactor to produce hydrogen and heat, air as the input of the air reactor to produce heat, and natural gas or other hydrocarbons as the inputs of the fuel reactor to produce CO₂ such as Equations J.4 to J.6 in each reactor

Steam Reactor: H₂O + Me (Metal) → H₂ + MeO(Metal Oxide) (J.4)

Air Reactor: Air + Me (Metal) → N₂ + MeO(Metal Oxide) + Heat (J.5)

Fuel Reactor: CH₄ + 4MeO (Metal Oxide) → CO₂ + 2H₂O + 4Me(Metal) (J.6)

The outlet gases from each reactor are supplied to the waste heat recovery unit (WHRU)

— Subprocess 2: WHRU

This subprocess exchanges the heat of the outlet gases and generates heat and electricity. At the outlet of the steam reactor, hydrogen is separated from the gas mixture, which consists of unreacted steam and hydrogen. At the outlet of the fuel reactor, CO₂ is separated from the gas mixture consisting of CO₂ and steam. The WHRU generates steam to supply to the steam reactor. According to the configuration of the CLWS system, additional energy, such as steam, heat, and electricity, is generated and/or required in the WHRU.

Figure J.2 — Example of a simplified CLWS plant block diagram – Subdivision in sub processes

— 2^nd Step: Allocations

Subprocess 1: CLWS Reactor

The feed (natural gas or other hydrocarbons) shall be allocated to hydrogen and steam according to their energy (lower heating value).

Subprocess 2: WHRU

The emissions from subprocess 2 are allocated to hydrogen and steam. The steam carbon footprint results from the allocation of combustion emissions of natural gas.

• • 1. Allocation in case of Consequential Approach [Informative]

In the case of a consequential approach, the goal of the LCA is to precisely define the boundaries considering consequential emissions. Under a consequential approach, the allocation of emissions to co-products may be avoided by applying substitution/system expansion with displacement, as described in Section 4.3.3.

• 1. Information to be Reported

Table J.2 — Information to Be Reported for CLWS

1. 
   
   Hydrogen Production Pathway – Geologic Hydrogen Production
   1. Geologic hydrogen process description and overview [Informative]

Sections K.1.1 and K.1.2 provide a description and an overview for natural and enhanced geologic hydrogen production.

• • 1. Description

Geologic hydrogen is a primary energy resource that is principally formed by naturally-occurring water-rock reactions in the subsurface. These reactions include serpentinization (an oxidation/reduction reaction between water and Fe²⁺ contained in the source rock) and radiolysis (natural radioactive decay splits water to produce H₂ and O₂). For the purposes of this Annex, a geologic hydrogen well is defined as a well that is drilled for the explicit purpose of extracting hydrogen. Therefore, a well that is originally drilled to extract a gas like natural gas or helium that may contain hydrogen is not covered by this Annex. Producing geologic hydrogen from naturally occurring reservoirs involves exploration to identify deposits, drilling a well, extracting the raw gas, and processing the gas to purify for final offtake. The first well to produce geologic hydrogen is located in Bourakebougou in Mali and has been producing hydrogen (98 % purity) since 2012. Early research into enhanced geologic hydrogen production is also underway. In this instance, production involves finding a suitable source rock and injecting a water-based solution into the source rock to enhance naturally occurring hydrogen generation rates or to initiate hydrogen generation. For enhanced geologic hydrogen production (also referred to as stimulated geologic hydrogen production), the in-situ reaction conditions have been engineered to optimize for hydrogen generation rates and/or hydrogen yield. Research into the concept of enhanced geologic hydrogen production is still very early days and is therefore mentioned in this annex for reference only.

Crude hydrogen from a geologic hydrogen well, whether from a natural reservoir or from an enhanced hydrogen production site, might require processing before being sold. The processing steps may/may not include^[16]:

— A two-phase separator to separate vapor and liquids (i.e., free water) produced at the wellhead

— A boosting compressor to increase the pressure of the crude gas stream from the wellhead pressure to the pressure for the downstream purification processing steps when the reservoir is at a low operating pressure.

— A gathering system to collect vapor and liquid production at a central location, especially for multi-well sites

— An acid gas removal unit to remove CO₂ and/or H₂S when the concentrations of either gas are significantly high (this may not be the case for all sites)

— Amine Gas Treating

— Liquid or Solid H₂S Scavenging

— A glycol dehydration package to remove residual water

— Gas purification equipment such as Pressure Swing Adsorption (PSA) units, membrane units, cryogenic distillation units, or combinations thereof, to separate and purify the hydrogen (H₂ + Helium) or hydrogen when the crude gas contains impurities/co-products (e.g., methane, N₂)

— When helium is present, a cryogenic gas separation unit or similar system to purify the hydrogen and helium if both gases are to be sold as separate products

— A compressor to pressurize the waste gas stream from the PSA unit for reinjection if the waste gases are to be reinjected into an injection well

— An emergency vent or flare system if the waste gases are to be flared

— Produced water treatment (e.g., pump skid, produced water storage tanks, injection well)

The exact equipment that will be required onsite will depend on the reservoir conditions (e.g., gas composition, flowing pressure), the wellsite design (e.g., waste gas reinjection, waste gas flaring), and the type of operation (production from an existing reservoir or an engineered production site). Importantly, since geologic hydrogen is a primary energy resource, the major steps involved in its production are gas purification and compression. Crude hydrogen gas will typically be a mixture comprised mostly of hydrogen together with N₂ and/or CH₄ and sometimes helium or other inerts.

• • 1. Overview

An example of a simplified block flow diagram for geologic hydrogen from an existing hydrogen reservoir with CH₄ and helium as co-products and waste gas reinjection is described in Figure K.1.

Figure K.1 — Example of a geologic hydrogen production with waste gas reinjection and helium is produced as a co-product

Figure K.1 includes electricity and fuel for onsite power generation but these two power sources can be supplemented by using a portion of the hydrogen produced onsite. For simplicity, the equipment required to use small amounts of hydrogen for power generation onsite is not included. This kind of configuration will lead to the lowest carbon intensity associated with geologic hydrogen production^[17].

• 1. Emission sources and inventory [Normative]

Sections K.2.1, K.2.2 and K.2.3 provide the emissions sources and inventory in case of attributional approach and consequential approach for geologic hydrogen production.

• • 1. Emission sources [Normative]

For geologic hydrogen production, the main sources of GHG emissions are fugitive emissions when CH₄ and/or CO₂ are present as well as emissions from waste gas management which will depend on the method (e.g., reinjection, flaring, venting). Other significant emissions sources include emissions associated with power production, especially when the power needs are supplied by the electric grid or fossil fuel combustion. Emissions that are incurred during the drilling and completions phase are considered CAPEX emissions (refer to Section 4.2.1 in the main text).

Emissions sources of each process unit or stage in the geologic hydrogen production process are outlined in Table K.1.

Table K.1 — GHG emissions summary for geologic hydrogen

• • 1. Inventory in case of Attributional Approach [Normative]

The emission inventory shall be performed across the life cycle stages from resource extraction to production gate.

Energy supply and upstream emissions:

GHG emissions associated with hydrogen plant third-party feedstocks, including natural gas, steam and electricity are evaluated based on 4.3.2.5.4, 4.3.2.5.3, 4.3.2.5.2 and Annex C.

Direct emissions at production:

Where direct measurements are not possible, the quantity of GHG emissions released into the atmosphere during the production lifecycle stage shall be determined by the carbon balance within the boundaries of the production facility. The greenhouse gas (GHG) emissions quantity in kgCO₂e is calculated according to the general principles outlined in 4.2.3.1.

Emissions from capital goods:

As per Section 4.2.1 the quantification of CAPEX emissions, primarily associated with the drilling operations, shall be provided.

• • 1. Inventory in case of Consequential Approach [Informative]

In case of a consequential approach, the inventory may be performed across life cycle stages extending beyond the production unit. The goal of the LCA should define the boundaries to consider the consequential emissions.

For instance the goal of the LCA may include:

— the emissions resulting from other means to produce the co-products like CH₄ or helium (system expansion) to assess the impact of substituting co-products from geologic hydrogen production for an equivalent co-product produced by other means.

• 1. Emission Allocation

Several co-products may exist for geologic hydrogen production including helium, CH₄, argon, and N₂. The exact co-products depend on the specific reservoir. Figure K.2 shows a simplified geologic hydrogen production facility where a pure (>99,9 %) hydrogen stream is produced in addition to helium and CH₄ as co-products. However, there may be cases where geologic hydrogen is produced and sold as <99,9 % pure hydrogen. In this case, emissions allocation shall follow the procedure outlined below and a corrected carbon footprint for hydrogen calculated according to the procedure outlined in Annex A.

• • 1. Allocation in case of Attributional Approach [Normative]

As described in paragraph 4.3.3, the first step for the emissions allocation shall be to subdivide the process.

— 1^st Step: Process subdivision:

The process shall be subdivided into 4 parts:

Given as an example in Figure K.2 and below, the unit process is subdivided into 4 sub processes.

— Sub process 1 – Crude hydrogen gas extraction: This sub process has electricity and/or fuel gas for power and utility water as inputs, produced water and crude hydrogen as outputs, and fugitive CH₄ and/or CO₂ as emissions. The crude hydrogen gas may be a mixture of H₂, N₂, CH₄, and may also contain other gases like CO₂, helium, and argon.

— Sub process 2 – Gas separation/purification: This sub process has crude hydrogen and electricity and/or fuel gas for power as inputs and hydrogen (H₂ + helium) plus CH₄ as a co-product, and a mixture of H₂/CH₄/N₂ as a waste gas stream. Emissions include CH₄ and/or CO₂.

Note: Depending on the resource, CH₄ may be a waste stream or a co-product of geologic hydrogen production. In the example provided below, some CH₄ is separated and reinjected as part of the waste gas stream, and some is produced as a co-product. Waste gas reinjection will give the lowest carbon intensity for geologic hydrogen production compared to alternatives (e.g., waste gas flaring, waste gas venting).

— Sub process 3 – Waste gas management: This sub process receives as an input the waste gas from the PSA unit and CH₄ and/or CO₂ emissions as output. The total emissions will depend on the waste gas management method selection (e.g., venting, flaring, reinjection). Reinjection gives the lowest carbon intensity for geologic hydrogen production.

— Sub process 4 – Cryogenic gas separation: This sub process receives as input a gas stream containing helium and hydrogen from the PSA unit and results in two purified streams of hydrogen and helium as output. Cryogenic gas separation consumes significant power which will result in emissions from onsite electricity generation or fuel combustion and/or upstream emissions associated with offsite electricity generation and offsite fuel production.

Figure K.2 — Example of a geologic hydrogen production with waste gas reinjection and helium is produced as a co-product – system sub-division

— 2^nd Step: Allocations:

Sub Process 1 – Crude Hydrogen Gas Production:

Emissions associated with onsite electricity generation, offsite electricity generation, onsite Fuel combustion, and Utility Water inputs as well as any CH₄ and CO₂ fugitive emissions shall be allocated to hydrogen and co-products (CH₄, helium) from Subsystems 2 and 4 pro rata their molecular content.

Sub Process 2 – Gas Separation/Purification:

The emissions associated with onsite electricity generation, offsite electricity generation, onsite Fuel combustion as well as any CH₄ and CO₂ fugitive emissions from Sub process 2 shall be determined and allocated to hydrogen and co-products (e.g., CH₄, helium) from Subsystems 2 and 4 pro rata their molecular content.

Sub Process 3 – Waste Gas Management:

The emissions from Sub Process 3 shall be determined and allocated to hydrogen and co-products (e.g., CH₄, helium) from Sub Processes 2 and 4 pro rata their molecular content.

Sub Process 4 – Cryogenic Gas Separation:

The emissions from Sub Process 4 shall be determined and allocated to hydrogen and Helium pro rata their molecular content.

Following the above considerations, the geological hydrogen production facility has two or more stages of co-product separation (e.g. first step separating CH₄ from the hydrogen and He mixture, followed by a second stage where hydrogen is separated from the He). The GHG emissions allocation shall be performed at each separation stage as follows:

— Determination of the total emissions associated to the stage j, (kg_CO2,e),

— Calculation of the allocation factor, based on molecular content, according to Equation K.1:

       Molar content (K.1)

With:

the number of moles of the stream i leaving the separation stage j (kmol of stream i), where the stream i is a single specie or a mixture of species (in this case the number of moles of the stream is the sum of the number of moles of all species present in the stream),

— Calculation of the attributional carbon footprint of the stream i (kg_CO2,e/kg of stream i) (Equation K.2):

(K.2)

Where the stream i is a co-product leaving the facility (e.g. CH₄), the is its carbon footprint for stage j. However, any GHG emissions (directly and indirectly) that may occur between the separation unit and the exit gate of the facility due to further transformation of the co-product shall be added to its carbon footprint (e.g. in this case CH₄ purification and compression, where applicable).

• • 1. Allocation in case of Consequential Approach [Informative]

In case of a consequential approach, the goal of the LCA should define the boundaries to consider impacts of consequential emissions.

Under a consequential approach, the allocation of emission to co-products may be avoided by applying substitution / system expansion with displacement as provided for in article 4.3.3.

• 1. Information to be reported [Normative]

Table K.2 shows the information that shall be reported for hydrogen produced from geologic hydrogen production.

Table K.2 — Information to Be Reported for geologic hydrogen production

1. 
   
   Hydrogen Production Pathway – Catalytic Naphtha Reforming
   1. Process Description and Overview [Informative]

Catalytic naphtha reforming is a commonly utilized process in crude oil refineries. The process converts hydrotreated naphtha (typically, but not exclusively distilled from crude oil) to an aromatic-rich mixture of hydrocarbons known as reformate, and relatively pure hydrogen.

Reformate has a higher octane-content than the naphtha from which it was made, and is utilized as a gasoline blendstock. It is also the primary industrial source of aromatic molecules such as benzene, toluene, ethylbenzene and xylenes (BTEX).

Hydrogen produced from the naphtha reforming is typically more than 99 % pure, allowing it to be used elsewhere in a refinery (e.g. for hydrotreating of naphtha) or for export/sale.

The chemical reactions underlying reforming processes are endothermic. Hence, external heat must be supplied – typically by furnaces fueled by refinery fuel gas or natural gas. These furnaces are typically designed to produce steam as well, increasing the energy efficiency of the reforming process. Power is also required to compress hydrogen separated from reformate. Specific heat and power requirements will depend on the catalytic reforming process employed in a refinery.

Two types of processes are predominantly used for catalytic naphtha reforming:

— Semi-regenerative reforming: This process features multiple reactors, each preceded by a furnace (or heat exchange loop within a common furnace) to supply energy for the aforementioned endothermic reaction. When the catalyst in one of the reactors has coked sufficiently, that reactor is put into a regenerative mode while the others continue to operate.

— Continuous reforming: This process continuously withdraws coked catalyst particles from the reactor, regenerates them, and returns them to the reactor.

The process illustrated in Figure L.1 represents both processes with respect to the emissions, inputs and outputs. Processes at individual refineries may vary. Although it is not explicitly illustrated in Figure L.1, carbon capture is technically possible, e.g. capture of CO₂ in the reformer flue gas, potentially using a portion of the steam generated as an energy source.

Figure L.1 — Example of a simplified catalytic naphtha reforming block diagram

• • 1. Emission sources and inventory

Sections D.1.2.1 and D.1.2.2 provide the emissions sources and inventory for the attributional approach for hydrogen produced from catalytic naphtha reforming.

• • • 1. Emission sources [informative]

For catalytic naphtha reforming, the main source of GHG emissions is the combustion of fossil fuel to provide heat for the reformer reactor(s). Other emission sources include

— Emissions associated with the production and transportation of process inputs (feedstock and energy).

— Emissions associated with purchased electricity for the operations illustrated in Figure L.1.

— Carbon Capture (not illustrated): If CO₂ is captured from the flue gas from the reformer reactor(s), then

— Emissions associated with process heating for the carbon capture process shall be included.

— Indirect emissions associated with the carbon capture process, as well as operation of CO₂ pipelines and facilities delivering CO₂ to permanent geological sequestration (CCS) shall be included.

Emissions sources of each process unit or stage in the catalytic naphtha reforming process are outlined in Table L.1.

Table L.1 — Potential GHG emissions in the life cycle of hydrogen produced via catalytic naphtha reforming

• • • 1. Inventory in case of Attributional Approach [normative]
         1. Energy supply and upstream emissions:

GHG emissions associated with hydrogen plant third-party feedstocks, including natural gas, steam and electricity are evaluated based on 4.3.2.5.4, 4.3.2.5.3, 4.3.2.5.2 and Annex C.

• • • • 1. Direct emissions at production:

The quantity of CO₂ released into the atmosphere during the hydrogen production stage may be estimated using the carbon balance within the boundaries of the plant. The total carbon input is determined from the quantity and characteristic of the feedstock and fuel. The total carbon output is the sum of

— Carbon in the CO₂ emitted

— Carbon in the CO₂ captured (used or sequestered)

— Carbon in the reformate produced and sold

— Carbon in the hydrogen product (i.e. impurities)

— Emissions of other possible carbon-containing species emitted, such as methane, volatile organic compounds (VOC), and CO.

NOTE: Other GHG emissions, such as N₂O, shall be accounted for.

• • 1. Emission Allocation

The three co-products illustrated in Figure L.1 will be produced by catalytic naphtha reforming, regardless of the specific process employed.

• • • 1. Allocation: Attributional Approach [normative]

Using an attributional approach, the energy use and emission burdens associated with the catalytic naphtha reforming process are allocated to the products by their physical attributes. The appropriate physical attribute in this case is energy.

The carbon footprint of hydrogen generated via the catalytic naphtha reforming process may be expressed symbolically as

(L.1)

In this expression,

, (L.2)

In Equations L.1 and L.2

— is defined in Equation L.2, and is the sum of greenhouse gases associated with the feedstocks,

— (kg input j) is the mass input of the jth material input (e.g. natural gas, hydrotreated naphtha, or refinery fuel gas); the sum is taken over all material inputs (i.e. it excludes power)

— (kg CO₂e/kg feedstock j) is the “raw materials extraction to gate” carbon intensity associated with the jth material feedstock delivered to reformer. These should be selected according to the criteria detailed in Appendix C.

— If the hydrotreated naphtha fed to the reformer was hydrotreated using a portion of the hydrogen from the reformer, this shall be appropriately reflected in the carbon footprint of hydrotreated naphtha via modelling of the hydrotreating process in accordance with ISO 14067.

— If refinery fuel gas is employed as a heat source and a carbon footprint of refinery fuel gas is not available via a publicly-available source as specified in Appendix C, then the “raw materials extraction to production gate” carbon footprint of natural gas (4.3.2.5.4) may be used to estimate the carbon footprint of refinery fuel gas.

— P is the product of the amount of external (e.g. grid) electricity input to the catalytic naphtha reforming process (kWh) and the carbon footprint of the electricity employed for the catalytic naphtha reforming process (kg CO₂e/kWh electricity delivered). If the power is sourced from the grid, then the carbon footprint of the purchased electricity shall be estimated in accordance with 4.3.2.5.2. If the power is generated at the refinery, then its carbon footprint shall be assessed in accordance with ISO 14067.

— D is the sum of the direct emissions associated with the catalytic naphtha reforming process (kg CO₂e),

— (kg) is the mass flow of hydrogen leaving the catalytic naphtha reforming process.

The allocation factor for hydrogen () may be calculated as follows:

(L.3)

In Equation L.3,

— is the lower heating value associated with the hydrogen product (J/kg)

— . is the lower heating value associated with the reformate (J/kg)

— is the specific enthalpy difference between steam at export conditions (temperature, pressure, quality) and water at plant feed condition (J/kg steam)

— is the mass flow associated with the hydrogen product (kg)

— . is the mass flow associated with the reformate (kg)

— . is the mass flow associated with the steam co-product (kg)

• • • 1. Allocation: Consequential Approach [Informative]

If hydrogen is produced via catalytic reforming, additional steam and reformate will be produced as well. A consequential approach employing the methodology of “system expansion via substitution” may then yield a formula for the carbon footprint of hydrogen of the type

(L.4)

In this equation L.4, the quantities , , , , , and are defined as discussed in L.1.2.1, and and are the carbon footprints of steam and reformate manufactured via other means. The bracketed terms on the right hand side of the preceding formula function as “credits” for displacing steam and reformate produced via other means.

The carbon footprint of steam generated by other means () will depend on the location of the refinery at which the catalytic reformer resides, the fuel source for that refinery, etc. If the steam generated by the catalytic reformer displaces steam generated by a natural gas boiler, then the carbon footprint of the displaced steam may be calculated as follows:

(L.5)

Here,

— is the carbon footprint of natural gas (kg CO₂e/kg NG),

— is the emission factor for natural gas combustion (kg CO₂e/kg NG),

— is the LHV of natural gas (kJ/kg natural gas)

— is the LHV efficiency of the displaced natural gas boiler, and

— is the specific enthalpy difference between steam at export conditions (temperature, pressure, quality) and water at plant feed condition (kJ/kg steam)

The carbon footprint of reformate produced via other means () is considerably more challenging to define, as there is no alternative method of producing reformate. One may consider expanding the system to include operations associated with the processing of reformate, and then formulate an equation for the carbon footprint of hydrogen as follows:

(L.6)

Here, S is the sum of direct and indirect emissions associated with the processing of reformate into benzene, toluene, ethylbenzene, xylenes, or high octane naphtha (a gasoline blendstock) and the sum on the right hand side extends over all such products.

Unfortunately, as of 2024, the only technology employed at scale for production of high octane naphtha and BTEX is catalytic naphtha reforming. Therefore, system expansion via substitution is not possible at this time, and no guidance is proposed for a consequential approach to emissions allocation for hydrogen produced via catalytic naphtha reforming.

• • 1. Information to be reported [Normative]

Table L.2 shows the information to be reported for hydrogen produced from catalytic naphtha reforming with carbon capture and storage.

Table L.2 — Information to Be Reported for Catalytic Naphtha Reforming

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1. In many European countries, methane sourced from the degradation of biomass under anaerobic conditions is referred to as “biomethane”. In the United States, it is referred to as “Renewable Natural Gas” or “RNG”. ↑

2. For carbon footprint in kilograms per megajoule, divide the CFP of hydrogen (kgCO₂e/kg_hydrogen) by the LHV of the hydrogen (MJ/kg_hydrogen), including impurities. ↑

3. Completeness, as defined by ISO 14044, is based on three criteria: mass, energy and environmental significance. Application of cut-off criteria to a given value chain can rely on the following three possible quantifications:
   a)   Transport activity: inclusion in the study of all inputs that cumulatively contribute more than a defined percentage of the transport activity within the transport chain;
   b)   Energy: inclusion in the study of all inputs that cumulatively contribute more than a defined percentage of the energy activity within the value chain;
   c)   Environmental significance: inclusion of all GHG sources that cumulatively contribute more than a defined percentage of the GHG emissions of the value chain.
   NOTE: This percentage can be specified by national regulations. ↑

4. Oil and Gas Methane Partnership (OGMP) 2.0 framework https://ogmpartnership.com/ ↑

5. https://www.unep.org/topics/energy/methane/international-methane-emissions-observatory ↑

6. Where water supply has been treated/processed, upstream emissions with that activity should be considered in building the emissions inventory ↑

7. In this illustration, “Waste” represents waste that has already been delivered to the “Waste Processing” facility. Emissions associated with transportation of waste from the site of waste generation to the site of waste processing fall within the system boundary of the product(s) whose manufacture generated the waste. ↑

8. Upgraded biogas is also known in some jurisdictions as “renewable natural gas” (RNG) or biomethane. ↑

9. In some cases, a SMR may feature a “pre reformer” if the feedstock (e.g. natural gas) contains ethane, propane, or other hydrocarbons of higher molecular weight) ↑

10. Allocation via energy content is predominantly conducted using LHV in the existing LCA literature addressing energy and fuels, including publicly-available tools such as GREET ^[1]. Energy-content allocation using HHV is employed in some LCAs. ↑

11. LHV is more commonly used over HHV in situations where the energy available in the water vapour is typically not recovered. ↑

12. Steam is almost always generated within the steam cracker plant boundary. This term is added for completeness. ↑

13. With regards to hydrogen compression and storage, it is important to be clear about the system boundary. Where compression and storage are required for the delivery of the functional unit (i.e. hydrogen under the specific boundary conditions), this must be included within the system boundary. ↑

14. Pressure Swing Adsorption (PSA) is applied to purify hydrogen up to required purity as hydrogen product. Remaining gases other than purified hydrogen are discharged as off-gas and can be recycled back into upstream process or used as fuel in the facility. ↑

15. Known as biogas or biomethane in EU, or as renewable natural gas in US. ↑

16. In addition to the above equipment, an enhanced geologic hydrogen production site may also include a pump to inject a water-based fluid into the formation, a metering system, injection well, and storage tanks onsite. For enhanced hydrogen production, a fluid heating system may also be required to drive chemical reaction rates. ↑

17. A geologic hydrogen producer may choose to valorize either methane and/or nitrogen as a co-product instead of treating as a waste gas and reinjecting into the reservoir. Alternatively, a geologic hydrogen producer may choose to vent or flare the waste gases rather than reinject. These scenarios will have implications for geologic hydrogen’s life cycle analysis and shall be reflected in the emissions sources inventory. ↑