Blue hydrogen is created from fossil sources, where the carbon emissions are captured and stored. Green hydrogen is made from non-fossil sources and favoured by policy makers who are wary of keeping the fossil economy going, even with CCS. As more regions commit to hydrogen, finding the right cost-optimal mix is crucial to its success. Schalk Cloete summarises his paper that models the whole system based on Germany. Integrating hydrogen will require a high level of technology interdependence. A wide range of parameters must be accounted for, including wind, solar, fossil plant types, storage methods, transmission, the carbon price, the different hydrogen generating technologies, imported hydrogen, and more. Cloete concludes that Blue hydrogen, where natural gas is converted to hydrogen, has significant cost and emissions advantages and should be considered very seriously.
There’s no denying it: Global political will is building behind the vision of a net-zero emission society. Europe wants to become the first net-zero continent and even China has recently jumped on the net-zero bandwagon, targeting 2060.
But we’re going to need a lot more than that. As shown below, the sharp emissions reductions Covid-19 caused in 2020 will need to continue if we want to achieve the 1.5 degrees target.
However, climate change tends to slide down the policy agenda during times of socioeconomic hardship, so we can expect emissions to resume their upwards trend when this pandemic finally subsides.

Image source: Climate Action Tracker
The good news is that clean energy has come a long way over the past two decades. Wind and solar power have seen great cost reductions and are leading the decarbonisation charge at present. However, there are two big challenges with a deep decarbonisation effort led by variable renewable energy (VRE):
- Wind and solar supply only electricity, which represents just 20% of global final energy consumption today.
- Wind and solar are variable and non-dispatchable, requiring additional technologies to supply energy when there is little wind and sun and others dedicated to consuming excess wind and solar power.
These two challenges have recently rekindled interest in the old idea of a hydrogen economy. Hydrogen is a carbon-free fuel that can decarbonise a sizable fraction of the 80% non-electric final energy consumption while simultaneously balancing VRE.
This is the premise we investigated in our recent paper published open access in the International Journal of Hydrogen Energy. In particular, the paper looked at the issue of capital under-utilisation involved in the strategy of balancing wind and solar with flexible hydrogen production.
Modelling the system (based on Germany)
To properly evaluate the effects of capital under-utilisation, we had to include all the major elements of the integrated electricity-hydrogen system: generation, transmission, and storage. The modelled system (based on Germany) is summarised in the image below:

Graphical summary of the modelled system. Electrolysers (PEM) are either located close to demand (in the “Flexible centralised demand” box) or close to wind power (in the “Co-location scenario” box). The numbers represent the following costs: 1) additional transmission costs for wind and solar; 2) conventional transmission costs; 3) hydrogen transmission; 4) hydrogen distribution; 5) reconversion of imported ammonia.
Five technology options
The following technology options were included:
- Ten different electricity generators: onshore wind, solar PV, pulverised coal and natural gas combined cycle plants with and without CCS, open cycle gas turbine peaker plants, hydrogen combined and open cycle plants, and novel gas switching reforming (GSR) concept.
- Lithium ion batteries for electricity storage.
- Three clean hydrogen generators: GSR, steam methane reforming (SMR) with CCS, and polymer electrolyte membrane (PEM) electrolysis.
- Two hydrogen storage technologies: cheap salt caverns with slow charge/discharge rates and locational constraints and more expensive storage tanks without such limits and constraints.
- Hydrogen can also be imported in the form of green ammonia that is reconverted to hydrogen in reconversion plants included in the model.
In addition, the costs of the electricity and hydrogen transmission network connecting all these technologies to demand are included in the simulation.
The model objective is to optimise the deployment and hourly dispatch of all these technologies to minimise the cost of the entire system.
Four scenarios: Green H2 [NoCCS, CoLoc] and Blue H2 [CCS, AllTech]
Our study considered two scenarios where hydrogen could only be produced via electrolysis (Green H2) and two where Blue H2 from natural gas with CCS was also allowed.
- NoCCS: All technologies are available except for power or hydrogen production with CCS. PEM is located close to demand.
- CoLoc: Identical technology availability to the NoCCS scenario, except that PEM is co-located with wind close to cheap salt cavern storage.
- CCS: Identical to the NoCCS scenario, except that conventional power and hydrogen plants with post-combustion CO2 capture technology are also made available for deployment. Only the GSR technology is not available.
- AllTech: Identical to the CCS scenario, except that GSR is also available for deployment. GSR is a novel flexible power and hydrogen production technology designed for the economic integration of higher shares of VRE.
The NoCCS and CoLoc scenarios differ in terms of the placement of the electrolysers. In NoCCS, electrolysers are located close to demand, meaning that wind and solar peaks must be transmitted through the costly transmission network to use hydrogen production for balancing VRE.
In CoLoc, electrolysers are deployed in the north of the country where the wind resource is good, and cheap salt cavern hydrogen storage is a possibility. This avoids the large electricity transmission costs of the NoCCS scenario, but it increases hydrogen transmission costs and restricts electrolysers to use only wind power from the north of the country.
The effect of Hydrogen demand…
It is highly uncertain how much hydrogen will be consumed in the clean energy economy of the future. In this study, demand was varied between 0 and 600 TWh/year, which corresponds to 0–33% of current German non-power oil & gas consumption.
Generation mix and CO2 emissions
With a CO2 price of €100/ton, the cost-optimal electricity mix looks like this in the four scenarios:

OCGT = open cycle gas turbine, NGCC = natural gas combined cycle, GSR = gas switching reforming, NGCC-CCS = NGCC with CO2 capture and storage, PEM = proton electrolyte membrane electrolysis, GSRH2 = GSR electricity consumption when producing hydrogen. H2 D&I = electricity consumption from hydrogen distribution and imports.
Green H2 scenarios
The two Green H2 scenarios (NoCCS and CoLoc) give similar results. In both cases, higher levels of hydrogen demand strongly increase the required electricity generation because of large demand from electrolysers (PEM).
However, a disappointing finding from this study is that no increase in wind and solar market share is observed as the level of hydrogen demand increases. For this reason, the CO2 emissions intensity of these scenarios stays relatively high.
The reason for this behaviour is the large capital under-utilisation involved in using electrolysers to absorb large wind and solar peaks, as will be discussed in more detail in the following section.
Blue H2 scenarios
In the Blue H2 scenarios, greater hydrogen demand does not increase the required electricity generation because hydrogen is produced via natural gas reforming. In the CCS scenario, there is no connection between hydrogen and power production, so the optimal generation mix remains unchanged with hydrogen demand.
However, the AllTech scenario shows that greater hydrogen demand increases the share of power production from GSR. When there is some demand for hydrogen, GSR can exploit its ability to flexibly produce either power or hydrogen to balance VRE while maintaining a high utilisation rate of most of the plant capital. This increases the VRE share in the optimal electricity mix.
Cost breakdown
As shown below, the Green H2 scenarios turn out to be considerably more expensive than the Blue H2 scenarios at higher levels of hydrogen demand.
The reason for this is that hydrogen produced from electrolysis will always be more expensive than the electricity used to produce it, whereas natural gas can be converted to hydrogen at a significantly lower cost than it can be converted to electricity. Thus, more hydrogen production increases the levelised cost of electricity and hydrogen (LCOEH) in the Green H2 scenarios and reduces it in the Blue H2 scenarios.

Unabated = fossil fuel plants without CCS, CCS = CO2 capture and storage, LCOEH = levelised cost of electricity and hydrogen.
The orange bars labelled “Other” amount to a substantial fraction of the total system cost in the Green H2 scenarios. This cost is examined more closely in the figure below.

T&D = transmission and distribution, PEM = proton electrolyte membrane electrolysis.
Green v Blue H2 scenarios’ transmission costs
Clearly, electricity transmission costs are the biggest component of the “Other” costs in the NoCCS scenario. This scenario locates electrolysers close to demand, requiring large additional transmission capacity to deliver the electricity produced by distant wind and solar farms.
In the CoLoc scenario, these transmission system costs are considerably lower because electrolysers are co-located with wind farms in the north of the country. However, hydrogen transmission and distribution (T&D) costs are higher in this scenario because hydrogen must be transmitted from the north throughout the entire country.
The CCS scenario requires only mild investments in H2 T&D infrastructure because hydrogen is generated according to market needs close to demand centres. These costs are significantly higher in the AllTech scenario because flexible power production from GSR implies a more intermittent hydrogen production profile, requiring more transmission and storage capacity to handle the intermittent hydrogen fluxes.
The effect of CO2 prices…
As illustrated in the previous section, the Green H2 scenarios still produced considerable CO2 emissions, even with a CO2 price of €100/ton. Achieving deep decarbonisation will require higher CO2 prices.
Generation mix and CO2 emissions
The graph below illustrates the effect of higher CO2 prices on the optimal electricity mix and CO2 emissions intensity. Hydrogen demand is set to 400 TWh/year in all cases.

OCGT = open cycle gas turbine, NGCC = natural gas combined cycle, GSR = gas switching reforming, NGCC-CCS = NGCC with CO2 capture and storage, PEM = proton electrolyte membrane electrolysis, GSRH2 = GSR electricity consumption when producing hydrogen. H2 D&I = electricity consumption from hydrogen distribution and imports.
Clearly, higher CO2 prices substantially reduce the CO2 emissions in the Green H2 cases by displacing unabated natural gas-fired power generation with wind and solar.
In the Blue H2 scenarios, an increase in CO2 price from 50 to 100 €/ton had a large effect by incentivising CCS in the power sector. Beyond this point, further increases in CO2 price have only a small effect because CO2 emissions are already very low at €100/ton. Most notably, higher CO2 prices incentivise more GSR and VRE in the AllTech scenario.
Cost breakdown
As shown below, the reduction in CO2 emissions in the Green H2 scenarios comes at a cost. Given their generally lower emissions, the cost of the Blue H2 scenarios is less sensitive to increased CO2 prices.

Unabated = fossil fuel plants without CCS, CCS = CO2 capture and storage, LCOEH = levelised cost of electricity and hydrogen.
In the NoCCS scenario, €200/ton is enough to allow the system to transition to using electrolysers instead of NGCC plants as the primary mechanism for balancing VRE. This is reflected in the considerable reduction in “Unabated” power production costs and the increase in “Other” costs when the CO2 price is increased from 150 to 200 €/ton. Other costs increase sharply because this strategy requires large transmission network overbuilds to transmit VRE peaks to electrolysers.
The CoLoc scenario shows a smoother trend. Here, increased CO2 prices also incentivise more VRE balancing via electrolysis instead of NGCC power plants. This also results in a steady increase in “Other” costs due to the lower utilisation rate of electrolysers, H2 transmission pipelines, and H2 storage infrastructure when handling increasingly pronounced peaks of intermittent hydrogen production.
This scenario is also highly dependent on the availability of cheap salt cavern hydrogen storage close to the co-located wind and electrolyser capacity. Such capacity is scarce around Europe, and its exploitation could face considerable public resistance. If more expensive tank storage must be used, system costs increase to the level of the NoCCS scenario, and 40% of hydrogen demand must be imported.
Only minor effects are observed in the Blue H2 scenarios, mainly the aforementioned transition from unabated power plants to CCS power plants when the CO2 price is increased from 50 to 100 €/ton.
Conclusions
The main conclusion from this study is that, although hydrogen can be used to integrate higher shares of wind and solar, this strategy brings considerable costs due to capital under-utilisation.
- When electrolysers are co-located with demand, expensive transmission network expansions are required to transmit wind and solar production peaks to electrolysers.
- When electrolysers are co-located with wind power, the low utilisation of electrolysers and the large hydrogen transmission and storage capacity required to handle intermittent hydrogen fluxes inflate system costs.
- When conventional CCS power plants are deployed, the model chooses to operate these plants under baseload conditions to maximise the utilisation of expensive CCS infrastructure, limiting VRE deployment.
- Flexible power and hydrogen production from GSR can integrate more wind and solar, but the associated intermittent hydrogen production increases hydrogen transmission and storage costs, reducing the positive impact of this novel process.
Such a whole-system perspective is critical for optimising the rollout of the energy transition. Given the high level of technology interdependence involved in such integrated electricity-hydrogen systems, careful planning is required to minimise costs and complexity. Blue hydrogen has an important role to play in this regard and should not be dismissed from the policy agenda.
***
Schalk Cloete is a Research Scientist at Sintef
Thanks a lot for your article and the thereto related research. I would like to ask you whether you have included production of hydrogen by pyrolysis of natural gas. If not, what are the reasons for not including this technology? Thanks in advance and best regards Daniel Buschgert
As far as I understand, there are still some important technical challenges related to separating the solid carbon formed in such a process. We actually recently got a project on molten salt pyrolysis – a promising methane cracking technology where the main technical challenge is the separation of the produced carbon from the molten salt. Furthermore, the market for the produced carbon would probably be small in comparison to the future market for hydrogen, limiting the contribution of such technologies.
Green or Blue Hydrogen Energy is still attached to a global energy system that is only 12% Efficient. There lies the Rub.
There are no real Green Energy Solutions. Wind and Solar Energy attached to a 12% Efficient system only make the problem worse as most Wind and Solar will end up in a landfill after its brief discounted cash flow lifespan.
What is not considered in Green Energy Solutions is the rapidly declining net energy from fossil fuels. Thus, we are heading into a Thermodynamic oil collapse much sooner than later.
I discuss the Thermodynamic oil collapse with Dr. Louis Arnoux here: https://www.youtube.com/watch?v=BxinAu8ORxM&t
Dr. Arnoux’s new Technology Class nGeni may be the only viable solution to tap into the 88% of waste heat generated by the total global energy system, which is now 140,000 TWh per year.
steve
I used to worry about these oil cliff theories too, but, after lots of subsequent thinking, I’m increasingly optimistic. Firstly, the world needs only about 4% of its productive capacity to produce energy. Even if this doubles due to the decline in fossil fuel resources and climate constraints, it means that we only need to move 4% of our economic output from producing other things to producing energy.
Secondly, the amount of economic output currently wasted on consumer items that have no or negative impact on our health and happiness is tremendous today, so there is massive scope to make this shift. Here is my article about that topic: https://energypost.eu/we-need-behaviour-change-and-life-efficiency-because-efficiency-gains-and-clean-energy-will-never-be-enough/. As a simple example, smoking and obesity costs the world about 4% of GDP today. If we stop producing cigarettes and junk food, we’d have freed up the required productive capacity to pay double for energy with a large net benefit to society. People are starting to understand this.
Third, innovation is progressing at a rapid rate. I don’t quite get the key novelty that will bring almost an order of magnitude gain in energy efficiency from Dr. Arnoux’s initiative, but there are many other innovations like this happening all around the world. Also, the declines in renewable energy costs are real, and, even though they will always be more expensive than fossil fuels on a system level, they are bringing down the ceiling of long-term energy costs to the manageable levels discussed above.
What I am worried about is the speed of the transition needed according to climate scientists and the impacts that this will have on the world’s poor. This is going to cost billions of happy life years in developing nations, especially if we keep insisting on making the energy transition almost exclusively through wind, solar, batteries, and electric cars, but there will be no cataclysmic global collapse.
I think the oxygen produced during production of green hydrogen can have many applications. This should be considered in the cost analysis of green hydrogen. As regards blue hydrogen, as long as there are natural gas utilizing industries eg power plants, the blue hydrogen that can be produced should be more cost effective.
Indeed, the O2 can have value if a good use can be found for it. I estimate it can have a value of 0.2-0.3 €/kg of produced H2 based on ASU costs – not much, but not negligible either. Of course, it will also need to be stored when hydrogen is produced intermittently, subtracting from this value. In addition, the best large scale uses of O2 are in oxycombustion applications with CCS, requiring CCS infrastructure. And, as you alluded to, this will mean that blue H2 remains the preferred option.
It seems to me that VRE transmission should be by electrical transmission lines including UHV DC which have known and proven transmission losses to the hydrogen production hub rather than by less known and more speculative H2 pipeline transmission.
PHES will have a vital role in VRE storage and is cheaper in the long run over 125 years than batteries.