by Alex Barnes, Independent Consultant and Director of Alex Barnes & Associates
Hydrogen Definitions and Why They Matter
Hydrogen produces no CO2 emissions when combusted or used in fuel cells. It’s therefore an attractive option to replace fossil fuels in certain industrial or transport sectors with the aim of reducing or eliminating their CO2 emissions. However, the actual production process of hydrogen may have CO2 emissions; replacing fossil fuels with hydrogen at the point of end use can therefore simply move CO2 emissions further up the energy supply chain, resulting in no net reduction in CO2 emissions overall. And, depending on the production method used, hydrogen production can result in more CO2 emissions than the direct use of fossil fuels.
Governments wish to ensure that hydrogen used to replace fossil fuels reduces CO2 emissions overall in order to meet their climate change targets. Hydrogen is not commercially competitive with fossil fuels and therefore needs to be subsidized. It would not make sense to subsidize hydrogen production and use that increased emissions.
Hydrogen can also be a ‘building block’ for hydrogen derivatives — chemicals or fuels — for example, ammonia or methanol, or ‘synthetic’ hydrocarbons such as Synthetic Aviation Fuel (SAF). As well as the carbon footprint of the hydrogen, production of the hydrogen derivative will also have emissions.
Finally, emissions from other greenhouse gases (GHGs) must also be included in the carbon footprint of the hydrogen produced. For example, methane is a powerful GHG in its own right, so any fugitive emissions of methane must be taken into account. Hydrogen itself is not a GHG but can react with other GHGs such as methane and thereby impact global warming.
How Green is Your Hydrogen?
Hydrogen does not occur naturally except in very limited quantities, so it must be manufactured. The carbon footprint of the hydrogen depends on how it is produced. To calculate the carbon footprint, you also must know which greenhouse gas emissions you are measuring, and how you are measuring them. These issues are at the heart of different governments’ proposals that define and certify the carbon footprint of hydrogen (see Table 1 and Table 2).
The term ‘high carbon’ hydrogen is used to refer to traditional methods of producing hydrogen with high CO2 emissions, such as steam methane reforming or coal gasification. ‘Low carbon’ hydrogen is used to refer to all forms of hydrogen with low CO2 emissions. These can include:
- Steam methane reforming (SMR) or auto thermal reforming (ATR) of natural gas with Carbon Capture and Storage (CCS)
- Coal gasification with CCS
- Electrolysis using low emissions electricity such as renewable electricity (e.g. wind, solar or hydropower) or nuclear power-generated electricity.
- Hydrogen production based on other renewables such as gasification of biomass or reforming of biogas. (Note if these technologies are combined with CCS the hydrogen can have a negative carbon footprint.)
- Other technologies such as methane pyrolysis which does not produce CO2 emissions but solid carbon which can be captured and stored or used more easily than CO2.
Table 1: Comparison of UK, US and EU Hydrogen Standards
1 Based on EU Delegated regulation for a minimum threshold for GHG savings of recycled carbon fuels and annex and EU Delegated regulation on Union methodology for RFNBOs.
2 Based on proposed EU Hydrogen and decarbonised gas market package and EU Delegated regulation for a minimum threshold for GHG savings of recycled carbon fuels and annex. Note that the Hydrogen and Decarbonised Gas package has yet to be agreed and passed into legislation. Details on the low carbon hydrogen definition are yet to be published.
3 Based on UK Low Carbon Hydrogen Standard
4 Based on U.S. Department of Energy Clean Hydrogen Production Standard (CHPS) Guidance (June 2023)
Table 2: Carbon Footprint of Hydrogen Produced by Different Grids Across Europe
The carbon footprint of hydrogen produced by an electrolyzer connected to the grid when renewable electricity is not being produced, will depend on the carbon footprint of all the electricity supplied to the grid during that period. The carbon footprint of the different grids in Europe varies hugely depending on the generation mix.
Thus, hydrogen produced using grid electricity in Poland could have a carbon footprint nearly 50 times greater than that produced in Sweden or nearly 10 times greater than that produced in France. If hydrogen produced using gas fired electricity is used to replace natural gas in a brick kiln, there would be a net increase in emissions. (Natural gas is often the marginal source of generation especially when the sun is not shining, or the wind is not blowing).
5 Source: EU Delegated regulation for a minimum threshold for GHG savings of recycled carbon fuels and annex.
6 Assumes electrolyzer uses 1.4 kWh of electricity to produce 1 kWh of hydrogen. Does not take account of any other emissions associated with hydrogen production.
7 Source: National Grid ESO.
The Need for Certification
Some form of certification system is often required to show that hydrogen meets the relevant definition so that the hydrogen can qualify for government subsidy. Governments may subsidize either production or consumption of hydrogen. In the latter case hydrogen consumers need to be able to prove that the hydrogen they use comes from a qualifying source.
Certification can enable trade in either low carbon, renewable hydrogen or derivatives such as ammonia or synthetic fuels by demonstrating a certain ‘quality’ of hydrogen to customers without the need for separate contractual arrangements with each customer. A standard and recognized certificate thereby makes trading easier.
Certification can widen the potential market for low carbon hydrogen or its derivatives by enabling them to be transported in the same systems (e.g. pipelines or ships) as traditional high carbon footprint hydrogen, ammonia or fossil fuels. It is essential that any certification system is robust enough to ensure proper tracking of the hydrogen and to avoid double counting.
Certification can also enable international trade, for example by ensuring that imported hydrogen meets the same requirements as domestically produced hydrogen. Certificates can ensure that imported hydrogen is eligible for subsidy to bridge the cost gap between fossil fuels or traditional high carbon footprint hydrogen and low carbon or renewable hydrogen.
Carbon Footprint Threshold and Methodology
Just as important as the carbon footprint threshold is the methodology to calculate the carbon footprint. This can vary with the types of greenhouse gas emissions included (CO2, methane, etc) and the extent of the supply chain covered.
A key consideration is what activities to include in the calculation of hydrogen’s emissions. This can be determined by the system boundary or the scope of the emissions.
The system boundary determines which activities are included in the measurement of hydrogen’s carbon footprints:
- ‘Well to gate’ includes emissions derived from the production and transport of inputs used in the production process (e.g. generation of electricity or production of natural gas). This is sometimes referred to as ‘upstream’ of the production process.
- ‘Well to wheel’ includes the same emissions as ‘well to gate’ but adds in emissions from the transportation and then use of the hydrogen or hydrogen derivatives. Emissions produced between the ‘gate’ and the ‘wheel’ are sometimes referred to as ‘downstream’ of the production process.
The scope of the emissions is a related concept and is defined by the Greenhouse Gas Protocol.
Emissions are categorized as follows:
- Scope 1 emissions: A production pathway’s direct GHG emissions
- Scope 2 emissions: GHG emissions associated with the generation of electricity outside of the hydrogen production facility, heating/cooling, or steam purchased for own consumption Scope 3 emissions: A production pathway’s indirect GHG emissions other than those covered in scope 2. This can include emissions from the upstream production of natural gas, manufacturing of equipment used in the production or transportation of hydrogen or emissions from the use of the hydrogen and its emissions. Scope 3 emissions are the Scope 1 or 2 emissions of other companies.
Proving an Electrolyzer is Using Renewable Electricity
It is easy to show that an electrolyzer is using renewable electricity if it is directly, and only, connected to renewable generation. However, electrolyzers may not be sited close to renewable generation and may be connected to the grid. As it is not possible to distinguish between electrons supplied to the grid, governments may require evidence of the use of renewable electricity.
Depending on the jurisdiction this can be done in different ways:
- Guarantees of Origin (GO) where a renewable electricity generator issues a certificate showing that it has generated a certain amount of renewable electricity in a given period. Other names include Renewable Electricity Certificates (RECs) or Renewable Electricity Guarantees of Origin (REGOs).
- Power Purchase Agreement (PPA) is a contract between an electricity generator and a consumer. PPAs are usually long-term contracts which may last up to 20 years or more. They provide certainty for both seller and buyer as to the quantity and price of electricity which is to be sold or
bought.
Where an electrolyzer is connected to the grid as well as directly to a renewable generator it may be necessary to use metering to show that the electrolyzer is not taking non-renewable electricity from the grid.
Renewable electricity such as wind or solar is intermittent and electricity cannot be stored easily. If the electrolyzer is connected to the grid, the only way to ensure that electrolyzers use renewable electricity is to require that hydrogen production takes place at the same time as renewable electricity generation (‘temporal correlation’).
The Importance of Additionality
Currently there is insufficient renewable electricity to meet current electricity demand, let alone expected increased demand as economies electrify. The EU Commission expects renewable hydrogen production in the region to require 500 terawatt hours of renewable electricity a year by 2030. This is only slightly less than the total quantity of wind and solar electricity generated in the EU today.
There is therefore a risk that hydrogen projects that sign contracts for the supply of renewable electricity could cannibalize existing renewable electricity generation which would in turn be replaced (in the short to medium term at least) by more fossil fuel generation. This would be very inefficient from an emissions point of view as 1kWh of renewable electricity can replace 1 kWh of fossil fuel electricity directly but can only produce 0.7 kWh of hydrogen due to losses in the electrolysis process.
For these reasons governments may put in place ‘additionality’ requirements to ensure that hydrogen projects contract with new renewable electricity generation. However, this can create a bottleneck for the projects because of the challenge that renewable projects may have in obtaining permits for construction or connections to the electricity grid.
Green Steel and Other Products That Use Hydrogen
Hydrogen can be used in a variety of processes, including:
- as fuel (either combusted or in fuel cells)
- as a feedstock for chemicals such as ammonia or methanol or synthetic fuels
- in the desulfurization of fuels in oil refineries or hydrogenation of biofuels
- replacing coal or natural gas in the direct reduction of iron (DRI) process to produce ‘green steel’
The lifecycle emissions from these processes will depend in part on the carbon footprint of the hydrogen. As is the case for hydrogen, the rules governing emissions accounting are evolving. Emissions trading schemes such as the EU or the UK Emissions Trading Schemes measure emissions at the point of production. As hydrogen does not emit emissions when combusted, the emissions are counted as zero. So, it is important to understand the source of the hydrogen when determining the ‘greenness’ of different products.
The EU has developed a taxonomy which defines the carbon footprint which products are required to meet to be considered ‘sustainable’. It is also developing rules to determine the carbon footprint of imported goods subject to the Carbon Border Adjustment Mechanism, such as steel, ammonia, hydrogen and fertilizers.
Hydrogen derivatives used as fuel, including in fuel production in refineries are covered by the same rules as for renewable hydrogen. The EU will develop rules for (non-renewable) low carbon hydrogen once it has passed the Hydrogen and Gas Decarbonisation legislation.
Spanish energy company Repsol is preparing to start production of sustainable aviation fuel (SAF) with a new 250,000 metric tons/year biofuel plant at its Cartagena industrial complex in the southeast of Spain.
Tomas Malango and Oliver Fernandez, Repsol’s Renewable Fuels and International Aviation directors, spoke on the sidelines of the IATA’s World Sustainability Symposium in Madrid in early October about the company’s plans to meet growing demand for SAF.
OPIS: So Cartagena is almost ready to produce SAF?
Malango: Yes. We’re in the commissioning stage, and our goal is to kick-start [the biofuel plant] before the end of the year.
OPIS: Is it going to produce both SAF and HVO (renewable diesel)?
Malango: Yes. It’s a plant that can operate in 100% SAF mode, producing around 200,000 metric tons/year, in 100% HVO mode around 250,000 mt/year, or in a mixed mode of both HVO and SAF.
OPIS: At current prices, what share of production would you allocate to SAF versus HVO?
Malango: I think it’s not about price, but about demand. Our plan is to start with higher HVO production. Then, as SAF demand develops, the plant would end up producing only SAF by the end of the decade. We’ll move with the market; if it demands more SAF, we’ll raise output faster.
We can’t deploy French fries restaurants to produce more SAF.
OPIS: Will your SAF market be Spain and Portugal, or will you be exporting as well?
Malango: We’ll be able to sell SAF as far as clients are willing to pay for it; it’s a strictly commercial issue. The product can travel; there is an existing infrastructure in place.
Fernandez: To provide some context, if the 2% SAF mandate started today, those 200,000 mt/year alone would be more than enough to meet the SAF demand of Spain and Portugal and have a production surplus. This surplus gives you optionality. There are airlines that want to go beyond the 2% mandate and are in the voluntary SAF market. The plant will be able to meet both mandated and voluntary SAF demand. Where? In Spain and Portugal. And then, depending on market dynamics, we might be able to go to Europe.
OPIS: What’s your forecast for the used cooking oil (UCO) market as a feedstock? Do you have any concerns about supply?
Malango: Waste is an anomalous type of commodity because you cannot increase waste production. Usually, when there is an increase in demand for a given commodity, supply rises to balance the price. With UCO, you have an existing waste that is mostly yet to be collected. In Spain, only 4% of domestic UCO is collected [at present]. We have a project to collect oils from the domestic sector at fuel stations, and we are working to build supply chains that are closer to Spain. But the UCO market is what it is and we have to go fetch it wherever it is. We can’t deploy French fries restaurants to produce more SAF. [UCO supply] will peak at some point.
OPIS: So now, in order to kick-start SAF production, have you had to source UCO from Asia?
Malango: From everywhere. We have national supply, European supply and Asian supply. We have a combination of supply contracts and our own supply chains that are being developed region by region.
OPIS: And Repsol is also planning a biofuel project in Puertollano, Spain. Is that going to produce SAF as well?
Malango: Puertollano will produce 100% HVO. This will allow us to free up Cartagena to produce SAF. Cartagena will start combining HVO and SAF production. When we have Puertollano running, we will be able to switch Cartagena to full SAF production by late 2025 or early 2026, depending on how the SAF market develops.
OPIS: Some companies are selling SAF indexed to oil prices. Is that the case for Repsol as well?
Malango: You have three ways of selling SAF in terms of price formula. One is fossil fuel indexation plus a green premium. Another one is the so-called “cost plus,” the cost of production plus a margin. The third one is an indexation to SAF market benchmarks, which take into account feedstock costs among other things. We work with all three formulas. It’s more a question of how the customer wants to handle the potential price volatility.
Fernandez: The airline industry has been using jet fuel benchmarks for many years. They have been buyers of a single product for decades. I believe airline reticence is not caused by switching to a SAF benchmark, but because they don’t have the capabilities to change, because they’ve been doing it that way their whole lives. It’s a market that is changing entirely, and so you have to sit down with them and explain that this is a new product with different dynamics and feedstocks, that it would be reasonable that, if you’re buying potatoes, you’re not indexing it to lemons, but to potatoes. There is some initial shock, but mainly because of that habit of using A1 jet fuel benchmarks.
Malango: But, in the end, it is sold the way the customer wants.
OPIS: And is it being sold via annual contracts with airlines?
Fernandez: The market is in its birthing phase, until a few weeks ago there was no regulatory clarity. The mandates were announced on Sept. 13. Until then, there were just people demanding SAF on the voluntary market with all types of contracts. We signed a pluriannual contract with Ryanair in May, and there are other contracts that are shorter.
But, above all, what producers and airlines want is to have regulatory clarity. You won’t sign any long-term contracts if you don’t know what the mandate is, what the obligations are, who bears the obligations, what is the obligation based on. Is it by airport? Annually? Quarterly? Weekly? Is it on a European or national basis?
There are many question marks. The path is not clear yet. We had a meeting with the MEP responsible for the law a few weeks ago, and he said that there are some details that aren’t likely to be clarified until June next year.
Today, airlines are saying “we need, we need, we need the product.” Perfect. From our side, we took the risk, our board green-lighted this investment four years ago, when the regulatory framework was even worse. The fact is that now we have it, at least to cover Spain and Portugal, so we are glad for airlines to come and see what contract formula they want, in terms of length and price indexation.
–Editing by Rob Sheridan, rsheridan@opisnet.com
Europe is striving to meet its targets in the journey to renewable energy and decarbonization as momentum in green hydrogen production gathers pace. With its abundance of solar and wind resources, Spain is aiming to position itself as the European frontrunner in green hydrogen and renewable energy. According to Cepsa, green hydrogen could soon be produced at a highly competitive price.
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Global law firm Shearman & Sterling LLP believes that more incentives are needed to develop a strong business case for hydrogen made from low or zero carbon energy sources. OPIS interviewed Mona Dajani, Shearman & Sterling’s global head of renewables, hydrogen and ammonia, and global co-head of energy and infrastructure, on the state of current regulations and the need for greater collaboration in the industry.
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