UK Special Coverage
Aberdeen’s Bus Scheme Failure Is the Latest in UK Net-Zero Madness
Scotland is learning it’s not easy being green.
UK Special Coverage
(John Keeble/Getty Images)
Aberdeen, in the northeast of Scotland, has for decades been the municipal heart of the UK’s offshore oil and gas industry. But in 2021, in pursuit of greening its public-transportation system and embracing its post-hydrocarbon future, the city put 15 hydrogen-powered double-decker buses into service and then enlarged the fleet to 25 the following year. The total cost: nearly £14 million. Yet by mid-2024, the entire fleet was inoperative owing to failures at the city’s two hydrogen refueling stations. And in August of this year, Aberdeen City Council announced that it would be selling the idled fleet for a total cost of just £816,000, a write-off of 94 percent, for buses that were in service only two or three years.
Explaining the decision, the city council stated, “As manufacturers and operators increasingly favor EVs, demand for hydrogen in transport has diminished.” In other words, per the city council, only a few short years ago hydrogen as a transport technology was in robust demand, worthy of a £14 million investment, but then EVs came on like a dark horse and now hydrogen is fading in the home stretch.
Nonsense. For years, about half of the hydrogen produced has gone into making ammonia as a feedstock for synthetic fertilizers, while roughly the other half has been put toward petrochemical purposes. Except for rare cases—e.g., forklifts that operate in enclosed spaces where exhaust would be a problem, forklifts whose owners require quick refueling times that rechargeable batteries can’t match—there has basically never been robust market demand for hydrogen-powered transport. (Political demand is another matter.) Globally, transport accounted for less than 1 percent of hydrogen demand in 2024.
At any rate, hydrogen is hardly a novel technology whose time just hasn’t yet come. Its manufacture and potential applications have been studied and understood for centuries. The electrolytic process of making hydrogen from water was first observed in the late 1700s by the Dutch chemists Jan Rudolph Deiman and Adriaan Paets van Troostwijk. The first hydrogen fuel cell was made in 1842 by the Welsh scientist Sir William Robert Grove. In the 1930s and 1940s, hydrogen in both gaseous and liquified form was being tested as aviation, jet-engine, and rocket fuel. In the 1950s and 1960s, Allis-Chalmers tinkered with using hydrogen in a variety of vehicles: tractors, forklifts, golf carts, even a small, manned submersible. NASA used hydrogen fuel cells to power onboard systems in its manned space-flight programs, starting with Project Gemini. And in 1966, General Motors developed the Electrovan, a concept vehicle with a propulsion system weighing nearly 4,000 pounds and built around 32 hydrogen fuel cells.
We’ve long understood the potential of hydrogen as a fuel source. The problem—which humanity once acknowledged but which we now too often skip past in the rush to validate alternative sources of energy—is that proof of concept is not necessarily proof of scalability and therefore economic sustainability.
On a Hydrogen FAQ webpage, Aberdeen City Council proclaims, “Hydrogen is the most abundant element in the universe” and is “potentially one of the most flexible energy solutions available.” On its own website, Aberdeen’s First Bus, the operator of the short-lived hydrogen fleet, informs readers of the following (boldface in the original):
Hydrogen is the simplest and most abundant element in the universe—made up of one proton and one electron.
Hydrogen releases zero emissions, it’s clean, green, and only emits water from the exhaust!
Hydrogen is made from wind and water.
Sounds wonderful. Simple, abundant, clean, green. But in fact, hydrogen’s simplicity is partly what makes the element so difficult and uneconomical to work with in most applications. Hydrogen is minuscule, with an atomic weight roughly one-quarter that of helium and a volumetric density roughly half that of helium. As a result, it’s difficult to capture, store, transport, and dispense. There’s much leakage and loss, which reduces its efficiency as a resource. To make it useful at any scale requires either compression or cryogenic liquefaction. The former involves pressures ranging from 5,000 pounds per square inch to 10,000 pounds per square inch. (The higher the psi, the greater the volumetric density and therefore the efficiency. By comparison, propane is transported and stored at pressures generally ranging from only 100 to 200 psi.) And liquefaction requires chilling hydrogen to at least -423 degrees Fahrenheit, only 30-some degrees shy of absolute zero. (For comparison, natural gas is liquefied at -260 degrees Fahrenheit.)
Both compression and liquefaction add to the cost and complexity of using hydrogen (involving specialized equipment, infrastructure, safety protocols, and handling, not to mention additional energy expenditures). What’s more, hydrogen is typically found bound with other elements in more-complex compounds, for example water (H2O) and methane (CH4). Therefore, at least at this point in human understanding, hydrogen can’t simply be found and extracted at scale, despite its abundance. It must instead be manufactured. So much for simplicity.
Most hydrogen (76 percent worldwide) is produced by a method called steam-methane reforming, which involves mixing methane (basically natural gas) and steam at very high temperatures and under pressure. Another 22 percent of hydrogen is made through a different thermochemical process called coal gasification. Needless to say, such methods are hardly a pathway to decarbonization and net zero. But the remaining 2 percent of hydrogen is produced by electrolyzing water. And it is here, at the fringe of the fringe, where one can find so-called green hydrogen—that is, hydrogen produced by electrolysis using electricity that is itself produced by renewables, specifically solar and wind. This is the source of First Bus’s claim that “hydrogen is made from wind and water.” As of 2022, per the Sierra Club, green hydrogen accounted for 0.02 percent of hydrogen manufactured worldwide, or just 1 percent of the small amount of hydrogen produced via electrolysis.
Why so little? Largely because wind and solar are intermittent, weather-dependent sources of power, and are therefore particularly unsuitable for sustained industrial processes. Even for domestic (i.e., non-industrial) electricity production, they require reliable, significant, and usually thermal backup. Aberdeen produced its hydrogen locally using electrolysis, but it did so by purchasing electricity off the national grid using what’s called a green tariff. Electricity from the grid is produced from a variety of sources, including fossil fuels, but the tariff theoretically serves to promote electricity production from renewable sources. It’s a sort of bureaucratic indulgence or sin tax more than a guarantee of anything truly green.
Prior to the collapse of the hydrogen bus fleet, however, Aberdeen City Council had entered into a joint venture with BP to produce green hydrogen locally. Comically, that plan (which was thought robust enough to one day produce green hydrogen sufficient not just for a fleet of city buses but for rail, freight, shipping, heat, and possibly export as well) rested on the development of a solar farm near Aberdeen. It’s comical because solar power in Scotland has a capacity factor of barely 11 percent, meaning that in an annualized average it produces only 11 percent of whatever its “nameplate” capacity is. (For example, 40 megawatts’ worth of installed, or nameplate, solar results in less than 4.5 actual megawatts of production.) Again, proof of concept is not necessarily proof of scalability or economic viability. And that joint venture is now in the process of being dissolved.
But even if the uhopian dream of mass-produced green hydrogen came to pass, the economics of the hydrogen refueling infrastructure (at least vis-à-vis that of petrol, diesel, and electric vehicles) would remain poor. “A hydrogen refuelling station,” notes Michael Barnard in CleanTechnica, “is effectively a small industrial plant, with electrolysers that have finite stack life, high pressure compressors, drying systems, storage vessels, safety systems, and specialized dispensers.” Barnard’s research has shown that the operating and maintenance costs of such stations tend to range from 20 to 35 percent of annual capital expenditures (Aberdeen’s were estimated to be around 30 percent), whereas annual O&M costs at EV recharging stations and simple old gas stations tend to be about 4 percent.
What’s more, because of their cost and complexity, hydrogen refueling stations can’t easily be replicated in large numbers like EV charging stations and gas stations—which makes a hydrogen-powered transportation system dependent on a small number of stations that, should any of them fail, can cripple the entire undertaking. (So much for hydrogen’s supposed flexibility, as Aberdeen learned the hard way.) Yet the consistent lack of real demand for transport hydrogen makes investment in hydrogen refueling stations and the vehicles that depend on them (and that the stations, in turn, economically depend on) a big risk over the long term.
It was in the face of such risk, which its city council knew about or at least should have known about, that Aberdeen launched its £14 million fleet of double-deckers. That fleet came into service after Aberdeen had run a 5-year pilot project involving 10 single-decker hydrogen buses. The pilot project demonstrated that although it was possible to run a small fleet of hydrogen buses, there was no actual demand—and even less economic reason—for doing so. When the pilot ended, the single-deckers were sold rather than kept in service as part of an expanded fleet (the lack of expansion indicating a lack of any real growth in demand). Further, at that point, the city’s refueling stations were five years down the road toward the end of their useful lives absent major refurbishing; per Barnard, electrolyzer stacks typically require such refurbishing within 10 years’ time.
Staring down the barrel of this looming maintenance, and without a hint of organic market demand evident from its pilot project, Aberdeen hopefully put £14 million worth of double-deckers into service anyway, buses that were expected to operate for 15 years and 1 million kilometers. Two years later, the required maintenance (and its economic reality) came due, bringing the whole thing to a radically premature end. As Barnard tartly remarks, “It was arithmetic catching up with ambition.”
Even under the best of circumstances, the economics of transport hydrogen are poor. For buses specifically (and including both capital and energy costs), diesel and electric buses operate at about £0.93/km and £0.59/km, respectively. For hydrogen buses running at their expected useful life, Barnard estimates that the cost would be £1.76/km–£2.23/km. For Aberdeen’s double-deckers, which ran only a small fraction of their useful lives, the costs are estimated to have been between £3.00/km and £4.00/km. Barnard again, even more tartly: “The math does not improve because policy hopes it will.”
Math, alas, has been the nemesis of much green-energy uhopianism and ambition. For instance, as mentioned above, solar in Scotland (on which Aberdeen pinned its green-hydrogen dreams) had a 2025 capacity factor of 11.1 percent, which happens to be that year’s UK average for solar. The UK averages for onshore wind and offshore wind were 24.1 percent and 36.2 percent, respectively. Allowing for modest, weather-related variations from year to year, that’s roughly their technological maximum in those locations and latitudes. By contrast, and regardless of location and latitude, natural gas as a technology has a much greater potential capacity factor. Twenty-six years ago, for example, UK combined-cycle natural-gas plants posted a 75 percent capacity factor. This is because natural gas (like nuclear, hydro, coal, and biomass) is a dispatchable form of electricity production, meaning it can run day and night, in any season and in any kind of weather, providing always-on baseload power.
Somewhat loosely speaking, capacity factor is a proxy for reliability (e.g., you can count on this or that technology X percent of the time over a year). You don’t increase your system-wide capacity factor, and therefore your grid’s reliability, by turning an ever greater proportion of your grid over to intermittent technologies with low capacity factors. Mathematically, quite the opposite. The system-wide UK capacity factor is now less than half of what it was a quarter of a century ago, which is partly if not largely a function of wind and solar accounting for less than 1 percent of electricity production in 2000 versus 37 percent in 2024 (the most recent year for which numbers are available).
Put another way, you don’t increase reliability by multiplying unreliability. (It’s like multiplying fractions.) Yet reliability is paramount, and has a price, which brings us to the supposed relative costs of the various technologies. In the past decade or so we’ve been encouraged to believe that on a per-unit basis (say, pounds per megawatt hour) renewables are the cheapest form of electricity production, cheaper certainly than natural gas. But given the gross discrepancies in the respective technologies’ capacity factors, this isn’t comparing like to like. To even appear (not really be) modestly more reliable than they are, renewables must depend either on grid-scale battery storage or on thermal, dispatchable backup—the latter usually in the form of natural-gas “peaker” plants used primarily for the purpose of backstopping intermittent renewables (cycling up and powering down over and over, as the variability of renewables dictates).
To use natural gas in this fashion is to use it in the least efficient and therefore most expensive way—the apparent costs of which are then attributed to gas as a technology and a fuel source, supposed proof of its relative unaffordability. And it’s true that peaker plants have particularly high costs per megawatt hour. But to borrow a word popular in certain energy circles, those costs are an externality of renewables. Peaker plants, as their name implies, are operated largely in an auxiliary fashion to renewables. So the costs are directly traceable to the ever expanding use of renewables. (Gas could otherwise be used for baseload power, much more efficiently and at a high capacity factor.)
The costs of grid-scale battery storage are another externality of renewables, costs that—given the material intensity of battery technology (the need for lithium, cobalt, nickel, copper, aluminum, lead, manganese, vanadium, etc.)—are subject to fluctuating commodity prices, supply-chain pressures, and the like. Those pressures and prices are often invoked as if to excuse the costs of grid-scale storage. (It’s not the technology’s fault! It’s not a failure of policy! It’s those darn supply chains!) But in fact, those pressures and prices are technologically inherent and must be (will be, whether we like it or not) priced into the use of such technology.
And sure enough, when you add the costs of battery storage and/or thermal backup to the capital costs of wind and solar, the supposed cost-competitiveness of renewables gets a lot more complicated and a lot less true (if not, depending on the country, outright false). One can put those costs on the scapegoats of fossil fuels, commodity markets, and supply chains, but those costs won’t go away until the technologies one prefers can truly, technologically obviate them.
Math. Aberdeen thought it could make hydrogen at scale through a continuous electrolytic process using intermittent, weather-dependent sources of electricity production, and then dispense that hydrogen on a cost-competitive basis through a refueling infrastructure that had operating and maintenance costs seven to eight times what is typical of other transport-refueling and -recharging infrastructures. The UK nationally over the past quarter of a century has seen its grid-wide capacity factor drop by more than half while its electricity prices have climbed to be among the highest in Europe. (Its industrial rates are the highest in Europe.) Over that same period, electricity production from intermittent, weather-dependent sources has climbed from less than one percent to roughly 37 percent of total electricity production. Yet the UK’s answer to the affordability crisis is to further increase the nation’s reliance on unreliable, low-capacity-factor sources of electricity production.
This, again, is like multiplying fractions and expecting a greater value, mathematically and otherwise.
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