Abundance is not the same as accessibility
It’s common to be told that hydrogen ‘is the most common element in the universe’, as if that in itself is sufficient reason to build future energy systems around it.
However there are problems with the statement. Hydrogen isn’t the most common element in parts of the universe we can reasonably access, for example the earth’s crust (where by mass it’s only 0.15%). And even in more obvious, concentrated and accessible sources such as surface water (H2O, after all), we don’t have hydrogen floating about in its elemental form.
So we can’t just drill for it or mine it, as we do with other ‘primary’ fuels. Annoyingly, hydrogen is found strongly bonded to oxygen, carbon and other elements – and it takes quite some effort to produce the hydrogen gas that we want.
There are many ways to separate hydrogen from its compounds. I won’t cover them all here, since many excellent reviews already exist (I’ve referenced one example at the end). Instead I’ll briefly compare current production with the most commonly discussed routes to ‘clean’ hydrogen.
The International Energy Agency (IEA) estimates that 75% of current hydrogen production is by separating it from natural gas, using steam methane reforming (SMR). Another 23% of current hydrogen production uses coal as the feedstock, particularly in China. In producing hydrogen from hydrocarbons, the clue is in their name: as well as hydrogen, we are also left with carbon. That’s fossil carbon and, released as CO2, it leads to huge climate-changing emissions from hydrogen production.
I’ve heard this dirty hydrogen production referred to as both ‘black’ and ‘grey’. Most current focus on how to clean up hydrogen production centres around two other options: ‘blue’ and ‘green’.
Blue hydrogen essentially takes black hydrogen production and adds a step, to ensure that the carbon – at least most of it – doesn’t get emitted to the atmosphere.
That means the challenges of growing blue hydrogen have little to do with hydrogen production.
Instead they have everything to do with carbon capture and storage (CCS). Or its more recent cousin: carbon capture and utilisation (CCU). Currently, only about a half of one percent of hydrogen production involves the capture of carbon.
Green hydrogen doesn’t utilise a hydrocarbon compound as the source for hydrogen. Instead it splits hydrogen away from oxygen, by zapping water with electricity: a process called electrolysis. So there’s no carbon to worry about. Of course crucial to denoting this as ‘clean’ is a requirement that we haven’t just shifted carbon emissions to the production of the electricity used in the process – this must be from renewable sources such as solar or wind. Currently, only about a tenth of a percent of hydrogen production uses 'green' electrolysis.
It’s my experience that low carbon ‘purists’ view green hydrogen production with much more enthusiasm than they do blue!
Partly this is because CCS cannot capture all of the fossil carbon emissions associated with steam reforming. But it’s common to hear objections to the fact that blue hydrogen production continues – indeed grows – demand for fossil methane. Unsurprisingly, traditional gas producers back many announced large-scale blue hydrogen plans.
Even to decarbonise current hydrogen production, there’s huge scope for clean hydrogen production growth. Even more so if we want to grow the total hydrogen market.
So what factors will determine whether clean hydrogen production is blue or green, or both?
It’s the economics, stupid!
Reporting numbers on costs is something of a fool’s errand: you can read five reports or talk to five different experts… and find ten different numbers! Which then age quickly. Start talking about future costs, with all the assumptions and uncertainties involved, and it’s harder still.
Nevertheless, cost competitiveness will clearly be crucial in determining how future hydrogen is produced. So it’s worth reviewing the factors influencing hydrogen costs going forwards.
To start, here are a couple of statements we can hopefully all agree on:
Blue hydrogen production is more expensive than black, because it’s basically the same production process, but with the extra costs of CCS/CCU.
Green hydrogen production has been more expensive than black, otherwise it wouldn’t be a measly 0.1% of the current market.
Let’s look at some numbers to back these statements up and explore how they might evolve. The numbers aren’t mine, so feel free to disagree with them!
Blue hydrogen depends on gas prices, carbon capture costs and carbon policy
The IEA reckon that (black) hydrogen produced from natural gas costs about $1 per kg in the US, a little lower in the Middle East, but more like $1.7 per kg in Europe (where gas is more expensive). Add CCS and those numbers jump by about 50%, so the lowest costs come in at around $1.5 per kg. (As a sanity check, IRENA arrive at similar minimum ‘blue hydrogen’ costs).
As with current hydrogen production, blue hydrogen is heavily dependent on the costs of the natural gas feedstock. So countries or regions with different natural gas costs will see different blue hydrogen production costs. Expect blue hydrogen to be more expensive in gas-importing countries. Depending on transport costs, they might become hydrogen importers instead.
Secondly, since fossil fuel prices are historically quite variable (and prone to ‘shocks’), blue hydrogen production brings with it those same future price risks.
Thirdly, to favour the production of blue hydrogen over black requires some mechanism which values captured carbon above the cost of capturing it: a high carbon price is the obvious one.
Green hydrogen depends on electricity markets and technology
The costs of hydrogen by electrolysis mainly depend on electrolyser cost and how often it operates (its ‘full load hours’); along with the costs of the electricity it uses. When an electrolyser is used infrequently (less than 30-40% full load hours), capital costs can dominate; for better-utilised equipment, electricity costs contribute most to the cost of green hydrogen.
In places with the lowest solar and wind power prices, IRENA suggest current green hydrogen costs range from $2.7 to $3.3 per kg; double the lowest cost blue hydrogen production. At less favourable electricity prices, green hydrogen costs rise substantially: IRENA estimate to between $4 and $7 per kg using typical wind and solar prices. (Another sanity check: BloombergNEF suggest green hydrogen costs range from $2.5 to $6.8 per kg).
Not everyone agrees with these numbers – I’ve seen claims that electrolysis can be competitive with black hydrogen today. I’m not here to dispute such claims, but suffice to say they usually depend on specific (and rare) sets of assumptions and circumstances: very cheap electrolysers fed with very cheap electricity, set against very high-priced gas prices and carbon penalties.
Future costs and predictable costs
Costs today are less important than their direction of travel. Remember, over 98% of the current hydrogen market is yet to be ‘cleaned’, even before we add any new hydrogen demand. That won’t happen overnight.
One thing analysts can agree on is that green hydrogen costs will go down. As electrolyser demand grows, so mass manufacturing and ‘learning curves’ will drive unit capital costs down. Renewable power costs will continue to fall too.
In my view, cost certainty is another important consideration for both hydrogen producers and buyers.
While blue production based on fossil fuels will be subject to feedstock price volatility, many sellers of renewable electricity will be more than happy to provide buyers with long-term fixed-price power purchase agreements (PPAs), which help them finance capital-recovery-dominated power plant investments.
As the major share of the cost of green hydrogen, stable electricity prices mean stable hydrogen costs. That long-term cost certainty could provide green hydrogen with a market advantage, even when its short-term cost looks uncompetitive.
Carbon capture: the big unknown for blue hydrogen
There are plenty of proposed blue hydrogen projects, from the Netherlands (‘H-vision’) to northern England (‘H21’) to Australia (Latrobe Valley). Many have bold aims of large scale. However it’s important to remember that scaling up carbon capture and storage remains a key uncertainty.
CCS is neither new nor a ‘quick win’, as a quote from a UK parliamentary briefing makes clear:
“Though commercially unproven in the UK, CCS has been identified since the early 2000s as a method of reducing UK CO2 emissions. However, CCS has been slow to develop… Although much of the associated technology is now well-developed, costs of deployment appear to be high and there is little policy incentive to capture and store CO2… There are currently few examples of commercial CCS plants globally.”
In particular, carbon capture and storage comes with considerable infrastructure requirements: not just in the carbon capture but in the logistics of transportation and sequestering. The economics of these are highly location dependent.
Many European blue hydrogen proposals are based around the North Sea, aiming to use existing oil and gas infrastructure, and storing carbon in depleted oil and gas fields. This approach should minimise the costs of CCS. It also appeals to existing oil and gas players, repurposing assets that otherwise risk being stranded. Having been paid for years to extract carbon from beneath the sea, perhaps the opportunity now exists to be paid to bury it there instead!
An alternative to large-scale carbon storage is a variety of emerging carbon capture & utilisation solutions (CCU). Fossil carbon is not permanently sequestered, but instead finds commercial value in a variety of uses from carbon fibre and graphite to construction materials and chemicals. There is much discussion over the extent to which CCU delays the emission of carbon, rather than removing it from the biosphere. It remains to be seen how quickly and on what scale CCU gains traction. Nevertheless, the approach of giving carbon a commercial value rather than relying on carbon prices could be attractive for kick-starting business cases for blue hydrogen.
Potential red lights to green hydrogen
It would be remiss not to mention barriers facing green hydrogen too.
Firstly, the scale of electrolysis is small at the moment. The average size of electrolyser additions from 2000 to 2009 was just 0.1 MW. This increased more recently, to around 1 MW over the last five years. That’s still relatively tiny.
The next few years will see multiple projects in the 10’s of MW range. For example at a refinery in Denmark, Shell plans a 20MW electrolyser by around 2022/23 – with potential expansion plans as large as 1,000 MW further into the future. So scale-up is happening.
However here’s a quote to bear in mind when we think about scale (it’s from the IEA):
“Producing all today’s hydrogen output from electricity would result in an electricity demand of 3,600 TWh, more than the total annual electricity generation of the European Union.”
Similarly, water requirements are not trivial: to produce all of today’s hydrogen by electrolysis would require over 600 million m3 of the stuff. (Based on 2017 figures that’s equivalent to the freshwater demand from almost 8 million UK inhabitants).
Sitting here in a UK winter, water supply can be easy to take for granted. It could be a serious resource constraint elsewhere.
Why not both?
Certainly, we will see both blue and green hydrogen.
Green hydrogen might be the purists preference, but lower costs combined with increased policy support for CCS (to meet newly-legalised net-zero targets) will in some places favour blue production.
Elsewhere, particularly for smaller-scale and direct-use hydrogen projects, green hydrogen will be quicker, easier and less financially risky to deploy.
In short we will see segmentation of clean hydrogen production methods, with competition based on location-specific input costs, scale targets and infrastruc