A few years back, hydrogen mostly cropped up in discussions over the future fuelling of cars. But that lunch is currently being eaten into by the inexorable growth and cost reduction of lithium-ion battery manufacturing. That’s not to say hydrogen won’t find a role in transport – it surely will – but it could be much more limited than its more fervent evangelists once hoped.
Luckily, transport is not the only market available to fans of this lightweight gas.
In this article I’ll show four charts which neatly sum up a key challenge in further decarbonising the UK energy system – our dependence on fossil-sourced natural gas, both for power and heat. That’s a key market opportunity, one which may suit hydrogen. I’ll also briefly introduce some of the issues and challenges that exist in grasping that opportunity. While the data is focused on the UK, the discussions have relevance elsewhere.
Chart 1. A good day for low-carbon power: January 7th
This and the next two graphs were sourced on the morning of 10th January 2019 from: http://electricinsights.co.uk/#/dashboard?period=7-days&start=2019-01-03&&_k=mjp4zj
January 7th was a good day for low-carbon energy, one which exemplifies the progress that the UK has made in recent years.
Even at peak demand, emissions intensity from power generation was just 200g/kWh. Wind (blue) provided nearly a third of supply, second only to gas (purple, just over a third). A few hours later, overnight, carbon emissions dropped to just 70g/kWh, with wind providing a fraction below 50% of supply. For fully two-and-a-half days, from around 9pm on January 6th, emissions stayed below 300g/kWh even at times of the highest demand (despite the fact that coal was part of the mix, unusual for the UK nowadays).
It’s this kind of chart that presents a good news story for advocates – like myself – of the transition towards a power system which is both cleaner and less reliant on (increasingly imported) fossil fuels.
Chart 2. Calmer and dirtier: peak time on January 3rd
By contrast, at peak time on January 3rd, carbon emissions stood at 350g/kWh, with wind providing only 4% of supply. Both coal and natural gas enjoyed increased activity in order to meet demand, the latter topping 50% of supply.
Coal (at least “unabated”) is due for phase-out by 2025. In recent years the removal of coal has been driven by a combination of lower demand (energy efficiency), growing renewables and substitution by growing gas usage. In the not-too-distant future, with coal gone, gas alone will top-up required supply during a similar “low wind” winter period.
Chart 3. The bigger picture: a full seven-day period
Rather than concentrate on specific time slices, be they “good” or “bad” in terms of our clean power objectives, we really need to take a step back.
The start of the week, January 3rd to 7th, provides an example of a problem that myself and other new energy advocates can’t avoid. Despite just over 20 GW of total installed wind capacity in the UK, its contribution never rose above 5 GW and was commonly somewhere between 2-3 GW. Not just for an hour here and there, but over the course of a whole few days. (Equally, when the wind picked up, it did so for a couple of full days, not in sporadic bursts).
These multi-day lulls in wind output are not uncommon. Also, in winter it’s clear from the chart that solar (in yellow) can have little to offer, despite an installed capacity of around 13 GW.
Growing renewables and the ‘calm winter day’ challenge
Forecasts for future wind capacity in the UK vary widely, depending mainly on deployment offshore, where land use and local opposition is less problematic. Some offshore growth forecasts reach 50 GW by 2050 or thereabouts. Even assuming a figure as high as 70 GW or so for total UK wind (on- plus offshore), that capacity would likely yield an output in a range ~10-15 GW during our January 3rd-7th lull.
There’s no question that building more wind will certainly help decarbonisation, reducing gas usage with every MWh of energy it generates on windy days. However even huge new wind capacity doesn’t remove the need for gas to provide flexible electricity supply, when the weather is calmer.
What of other options?
By the time we’ve built out that much wind, we’ll also have substantially more interconnection capacity with our neighbours. For flexibility, more connectivity with adjacent power systems is a good thing. However what will be the carbon intensity of the electricity that we import? Are we simply swapping one import (electricity) for another (gas)? Those questions frame important policy discussions, but are for another day…
Current government policy is to grow nuclear capacity too. However an ageing fleet and the deployment costs, financing challenges and timescales around new builds make that an increasingly uncertain prospect. Without moving the technological, financial or regulatory goalposts, it seems ‘brave’ to bet a substantial chunk of our decarbonisation pathway on nuclear.
What about biomass, hydro and solar? On a large scale, development of new biomass seems limited and new sites for large hydro are few. That’s not to say they won’t grow at all; just that they may not dent the market share of gas that much. Solar will certainly grow, given plummeting costs, but the charts indicate how limited a contribution it makes when calm and dull weather coincide.
If we do build huge wind capacity, we’ll of course find ourselves with excess capacity during those windy periods between the lulls. In theory, this excess could be large enough to store sufficient energy to replace natural gas when the wind drops. We’ll certainly have large excesses of supply during the summer too, when demand is substantially lower (but, at times, winds are still strong). In summer, large solar capacity will contribute to periods of oversupply too.
Rather than curtail renewable electricity output when we have too much at a particular time, wouldn’t it be better to store it and use it later, when we don’t have enough?
Therefore one theoretical solution to fully removing gas from our electricity mix is to overbuild low-carbon wind and solar capacity, then shift their output using storage. But that storage can’t be the few-hour lithium-batteries of today – we need to shift energy over periods of several days within a season and between seasons within a year.
If existing (or new) storage technologies can’t scale to meet that challenge at competitive cost, then many analysts believe that hydrogen provides an alternative energy carrier – one which can be stored for such lengthy periods. After all, another gas (natural gas) is already stored at scale today, in its pipeline networks or in large underground caverns. So why not substitute hydrogen gas instead?
The key new technology breakthroughs needed for this are less to do with the storage part. They are more to do with scaling up, increasing the efficiency and reducing the cost of producing hydrogen by using our “excess” renewable power: splitting it from water using electrolysis. And, of course, in creating an investable business case to generate, store, shift and sell energy on these time and capacity scales.
Chart 4. The elephant in the natural gas room: heat demand
So far we’ve looked at electricity demand and supply. This next chart is from a different source, here: http://www.ukerc.ac.uk/asset/A4C0F350-8FF5-41EE-B20DD0DEA2501641/
The chart shows both Britain’s hourly local gas demand and its electrical system supply, on the same scale, for the period 2nd April 2017 – 6th March 2018. Whereas electrical demand peaks annually at around the 50GW mark, gas demand – in winter – is much, much higher. That’s because natural gas provides around 70% of UK heat supply in addition to around 40% of electricity – and heat demand dwarfs electricity demand in the colder months.
That means decarbonising the gas used for power generation is really the easy part – but it addresses only a small chunk of the UK’s gas-sourced carbon emissions. We need to decarbonise heat too (and continue to work hard to use less of it, through better insulation).
Some clean energy advocates focus on the electrification of heat, on the basis that we could provide electricity from clean sources like wind or solar. After all, we just talked about building very large power capacities going forwards.
But just imagine how much capacity we’d have to build to meet that size of heat demand!
Demand could be less than suggested by the gas numbers on Chart 4, if we combine lower losses with a move to using heat pumps, which can collect two to three times as much heat as the electricity used to power them. Nevertheless – and notwithstanding the practical retrofit hurdles of mass heat pump deployment – the low-carbon capacity needed to electrify and decarbonise heating would remain much larger than that needed to replace natural gas in just the power sector. And the seasonal differences would be even further exaggerated.
Given that we can burn hydrogen fuel to create heat, that opens up another market opportunity – potentially an even bigger one than simply storing and time-shifting clean electricity.
Gas substitution: from natural gas to hydrogen
We already have gas pipelines to distribute natural gas for heat use, so it sounds sensible to make use of these existing assets to transport hydrogen. We could do so either as a blend or as a full replacement (with necessary upgrades to the pipes and to end-users’ appliances).
Again the bigger practical problem is not the distribution of hydrogen gas, it’s how to scale up its production in the first place. If scaling up using electrolysis sounded challenging when we looked at power demand, it looks even more-so when we add in heat!
To give a sense of this scale problem, consider that the biggest electrolyser in the world is being built in Germany. It will be 10 MW (peak capacity) and operational by 2020. Total global electrolyser capacity by then is likely to be somewhere above 150 MW. Yet the scales on our charts read in GW, three orders of magnitude higher.
Even armed with policy support and viable business plans, it will take industry a lengthy period and plenty of cash to scale electrolysis deployment to match even our current build-out of low-carbon electricity, let alone future additions.
CH4 + 2H2O -> CO2 + 4H2
Today, the production of hydrogen at larger scale uses techniques (such as steam reforming) which separate it from fossil fuels: natural gas, oil or coal. These are cheaper than using electrolysis. Illustrating the point, that plant in Germany already produces nearly ten times as much hydrogen from natural gas each year as it will via its new electrolysis addition.
That’s why projects such as H21 in northern England propose using natural gas as a source of hydrogen. The latter will then be delivered through existing natural gas distribution networks (plus some specific new pipelines).
In isolation, this idea sounds nonsensical.
Converting natural gas to hydrogen is not 100% efficient: so the hydrogen carries less energy than the natural gas from which it was produced. For the same end-use energy throughput in hydrogen, we’ll need more natural gas than if we used the latter directly. No surprise that traditional gas-producing companies such as Statoil and Shell are some of the keenest promoters of hydrogen pathways. It remains to be seen whether policymakers will be enthused, with the UK an increasingly gas-importing nation (and with the growth of domestic shale gas embroiled in regulatory battles and protests).
On its own, this gas-to-hydrogen approach also fails to address decarbonisation: it uses fossil natural gas whose carbon is released along with hydrogen when CH4 is split. Indeed it makes things worse: because it requires more natural gas, to cover those conversion losses.
Look further into H21 though and you find that an essential element of “clean hydrogen” projects like this one is carbon capture and storage (CCS). The carbon released needs to be stored permanently underground. If natural gas is the feedstock then it is CCS, not hydrogen, that is the determinant of decarbonisation .
CCS has never gained traction at power plants, despite being talked about for many years. However it is something that oil and gas companies have experience with – because pumping CO2 into a reservoir can helpfully push more fossil fuel out. So the principles are understood – and growing the technology presents a further business opportunity for those companies. The key questions are around costs and the ability to scale up carbon-storage to accommodate country-sized emissions.
In a nod to the renewed interest in the role of CCS to tackle the more challenging issues of decarbonisation, the UK government published its “deployment pathway action plan” on the subject late in 2018. Their ambition is to achieve the option to deploy “at scale during the 2030s”, so some time away and with the important caveat “subject to costs coming down sufficiently”.[Attentive readers will note that the document refers to CCUS: carbon capture usage and storage. Carbon dioxide is an important industrial gas, so this definition includes using the captured carbon in the production of chemicals, or even other innovations: such as one in which carbon is directly captured as graphite for use in Li-ion batteries].
A route to market: distribution first, production follows?
It’s worth noting that electrolysis and hydrogen-from-methane aren’t mutually exclusive pathways.
It’s also worth being aware that there are other clean hydrogen production methods out there, hydrogen from biomass and solar-to-hydrogen as examples. They are at various stages of development, interesting and worth keeping an eye on. Currently, I’d consider them a very niche part of the conversation – but different future options are always good to have.
Hydrogen from a combination of sources can ultimately feed into the same gas delivery infrastructure. If hydrogen-from-methane is the more quickly scalable pathway, we can use it – in combination with CCS – to create a business case to fund those infrastructure investments (upgrades and new pipes). That is a key theme of the H21 proposal. Scaling more quickly also addresses decarbonisation more urgently.
In future, with that infrastructure already paid for, we can then evolve to injecting electrolytic hydrogen sourced directly from low-carbon electricity as and when that production scales (along with bio-hydrogen or others).
There are risks to that last assumption of course: by first scaling hydrogen-from-gas, its cost advantage is likely to grow further, making market entry for alternative production methods harder. So though hydrogen + CCS may offer a route to decarbonisation, it may lock us into a dependency on primary fossil natural gas feedstock.
On the other hand, if we choose not to follow the methane-to-hydrogen pathway and electrolysis is small, how can we make the investment case for building or upgrading to large-scale hydrogen distribution networks? And if it can’t be distributed at scale, there’s no route to market, so where is the investment case to produce it at scale? That’s a classic chicken-and-egg market growth problem.
Hopefully I’ve piqued your interest in hydrogen. I focused first on establishing why a potentially large market opportunity exists for hydrogen, at least here in the UK. I then outlined some of the options around where hydrogen might come from, including some of the issues that arise as a result.
Clearly there are big opportunities for hydrogen, but a whole range of technology, policy and business challenges to be navigated before deciding how, if and when those opportunities can be taken. There are other competing alternatives: and I’ve certainly not discussed them all here. All of these will evolve or emerge in the time taken to scale up hydrogen, shifting the business and competitive goalposts.
The reality is that to decarbonise gas we’ll deploy a combination of solutions. The question for hydrogen is whether it can become one of the biggest.
I’ll focus on some of the specific issues raised (and the alternatives) in future articles.
As always, get in touch if you want to discuss the issues in more detail or think I can help your business make progress in the clean sector through business education, strategy advice or market analysis.
(This article was first published via LinkedIN, here)