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May 2021 – open access articles The following articles are taken from Energy World magazine’s May 2021 edition for promotional purposes. For full access to the magazine, become a member of the Energy Institute by visiting www.energyinst.org/join
Nuclear energy
CLEAN POWER
Nuclear or gas on the path to net zero?
We can all agree that renewables are the future for clean electricity generation, but what should support this growing sector – gas with carbon capture or nuclear power, or both? If nuclear, are the days of building full-scale reactors coming to an end, to be replaced with modular alternatives? Nick Cottam ponders.
P
oliticians love big projects with big numbers and the current UK administration is no exception. HS2, Hinkley Point, Sizewell C, even the much-derided track and trace for virus detection – all of these mega projects have conjured up eye wateringly large sums of money and all have proved difficult to quantify and evaluate. Perhaps this is why politicians love them so much. Nuclear power, in terms of both cost and necessity, is a particular conundrum. Do we need a new generation of vastly expensive, long lead-in nuclear power stations now we have so much renewable capacity? Can we not carry on relying on gas and LNG to fill the load on those calm, cloudy days – at least in the short to medium term? At a recent IP Week event, held online in February, there was some debate about whether LNG was now a transition or still a so-called destination fuel. ‘At the end of the day, customers want reliable energy and gas offers
16 Energy World | May 2021
this flexibility,’ noted one of the speakers, Total’s CEO Patrick Pouyanné. The fast-talking Pouyanné went even further: ‘the word transition doesn’t mean we can do everything in a minute.’
A suitably futuristic image of a Rolls Royce Small Modular Reactor Image: Rolls Royce
Huge investment The reality is that Total and other oil and gas majors are juggling on the road to net zero and so are our politicians – the problem being that it really does take time and huge investment to build new energy infrastructure at scale. If nuclear commitment continues to wobble in the UK and gas is seen as an acceptable destination fuel for the foreseeable future, then another big ticket investment like carbon capture and storage (CCS) would surely have to become part of the mix. The quandary then remains – grow renewables as fast as possible but stick with gas and a large injection of carbon-gobbling CCS to cover baseload requirements for electricity, or wind down the gas,
keep costly CCS to a minimum and make it renewables plus next generation nuclear. The latest Drax Electric Insights report for Q4 2020 headlines the fact that renewables, in the form of wind, solar, biomass and hydro, provided just under 40% of UK electricity over the whole of 2020. While renewables output has increased ten-fold since 2010, fossil fuel output has fallen 60%, it noted. In short, renewables plus nuclear are doing much of the heavy lifting but there’s also a new generation of gas fired power stations in service and gas is still providing important back-up when either renewables or nuclear fall back for one reason or another. Add to this the fact that all but one of the UK’s existing fleet of nuclear power stations will be decommissioned by 2030 and you can see why the pressure on decision makers is mounting. That said, the UK’s decisionmaking process for next generation nuclear has been sclerotic to say the least. Love of large, grandstanding
Nuclear energy
projects just doesn’t seem to be enough when a project like Hinkley Point C in Somerset will only deliver electricity at an agreed price of over £90 per MWh; this compared with a future renewables price likely to dip below £60 per MWh for the new generation of offshore wind farms. As the cost of wind and solar developments continues to fall, Hinkley Point’s development costs have risen by a whopping £5bn to over £23bn in the last five years and the station will cost almost double that projected in 2008, although developer EDF will be picking up the construction bill. Ageing nuclear While the pandemic has pushed back Hinkley C’s expected startup date to mid-2026 and added another £500mn to costs, most of Britain’s ageing fleet of nuclear reactors are stuttering towards end of life. Only Sizewell B in Suffolk will still be running after 2030 and other stations could well be out of action long before 2030 for essential maintenance work – another factor helping to concentrate political minds. This means more pressure on gas and renewables to take up the strain and more reason to get on and make a proper decision about nuclear. ‘Nuclear power, in partnership with renewables, is essential to reaching net zero’ noted Tom Greatrex, Chief Executive of the Nuclear Industry Association, recently. He also added that: ‘the time has come to build a new fleet. That investment, as part of a robust zero carbon mix, will kickstart a green recovery and our transition to a green economy.’ Waiting in the wings is Sizewell C, which could generate 3.2 GW of electricity, enough to meet 7% of the UK’s electricity needs according to EDF. ‘The electrical output would provide a low carbon source for over 20% of the UK’s homes and, based on current grid intensity, offset approximately 7mn tonnes of carbon dioxide per annum,’ notes the company in its Sustainability Statement. ‘The development of the Sizewell C project would therefore play a significant role in the UK’s transition to a low carbon economy,’ it projects. Aside from filling baseload, net zero is the holy grail and if you put aside the cost factor, nuclear looks a good bet for consistent, load-filling clean energy. The big caveat from the Stop Sizewell C (SSC) campaign are the emissions, which would result from a protracted construction process, which EDF itself puts at 5.7mn tonnes of
Bigger is usually better with nuclear, which either suggests the SMR approach is dead in the water or that the big project advocates are missing something fundamental
carbon equivalent. SSC has called for a lifetime assessment of the carbon footprint of both Hinkley Point C and Sizewell C but as yet this has not been forthcoming and EDF has apparently declined requests on the grounds of commercial sensitivity.
option. ‘This is real,’ he says, claiming that the company now has an investable design which could be produced in the high hundreds and above for use in the UK and overseas. ‘This is a realistic and low risk programme,’ he said recently. ‘One of the key scaling factors in What price carbon? the design is the use of digital twinning. Right from the start we’ve In terms of future UK energy looked at a hybrid licensing model options, it’s important to distinguish between what’s on the where initially the UK consortium makes all the power stations but as table, what’s down the line and we get foreign interest, parts can be what could happen with enough nudges and favourable investment exported and other and other parts can be made by those countries that decisions. If the COP26 meeting in Glasgow in November, for example, subscribe to the right licensing authority,’ adds Stein. has the courage to set a carbon While Tom Greatrex claims that price, this would almost certainly nuclear power can kick start a green make CCS seems like a better bet recovery: ‘and our transition to a for energy companies. green economy,’ his most recent NIA Will the UK and other countries statement is all about building a do more to skew the market in new nuclear fleet – scale again – favour of hydrogen? Can there be rather than the SMR approach. new funding/electricity pricing Advocates tend to agree that bigger arrangements for Sizewell C and is usually better with nuclear, which any other future nuclear stations either suggests the SMR approach is deemed necessary? These are all dead in the water or that the big factors which will have an impact project advocates are missing on the future energy mix – eg the something fundamental. load-bearing share of gas and RR’s Stein adds: ‘One of the nuclear. beauties of the SMR approach is it Offshore wind and solar will becomes quite a low-cost source of continue to power on, but more energy for other parts of the sophisticated storage solutions are decarbonisation scene, such as needed here. Gas is a lower carbon hydrogen and synthetic fuel. One alternative to coal and oil but all UK SMR and plant will be able to fossil fuels must factor in CCS if the produce 170 tonnes of hydrogen or UK is serious about reaching net 280 tonnes of net zero synthetic fuel zero by 2050. per day.’ Here then is a red-blooded Hydrogen is emerging at speed manufacturing approach to nuclear but, as noted, it needs lots of help/ energy – power in bite-sized chunks investment to scale up. As BP’s CEO distributed to exactly where it is Bernard Looney said at IP Week: needed but not the grandstanding ‘hydrogen has the attraction of capex solution of a Hinkley or a being almost an LNG-type business Sizewell. in its infancy. As we look at the Stein again: ‘The UK SMR heralds period 2030 plus, hydrogen is going a new approach to the cost of to play a significant role. BP would like to capture about 10% of the key nuclear power by broadly rethinking the manufacturing and markets when the key markets construction methods and by the evolve.’ extensive use of digital twinning, whilst keeping the physical package Rolls-Royce trumpets SMRs exactly the same. This is a That leaves nuclear, still on the pressurised water reactor of the table as the other large-scale type we know and love.’ clean energy source but, in the UK In reviewing all these at least, the government is still arguments, one is left with the scrambling around for acceptable funding models. Looney maintains conclusion that the UK needs some that you have to believe in scale for brave and thoughtful decision making to get the right energy mix. individual projects – the oil man’s Can a choice be made between gas narrative – but how much scale in the case of nuclear? The alternative and CCS to support renewables, and the alternative of nuclear plus is the type of small modular reactor (SMR) now being promoted renewables? Or is there a fudge by Rolls-Royce which could be built which says we can carry on throwing a bit of everything into for under £2bn in a fraction of the time and disruption of a Hinkley or the mix? A cost of £45bn for two Sizewell and apparently still power new nuclear power stations suggests not – even in an age of a city the size of Leeds. COVID. l According to Rolls-Royce’s Chief Technology Officer Paul Stein, the SMR is very much on the table as an Energy World | May 2021 17
Nuclear energy
DECOMMISSIONING
Three EU countries push forward with nuclear phaseout Some European governments have been sceptical, or outright hostile, towards nuclear energy for decades. Now the countries which are doing away with their fission power plants are reckoning with the tricky issue of decommissioning, write Liz Newmark, in Brussels; Jens Kastner, in Hamburg; and Brenda Dionisi in Milan.
T Belgium’s Doel nuclear power plant near Antwerp is slated for closure – with nuclear going the way of old-style windmills as an energy source in this low country kingdom Photo: Trougnouf 18 Energy World | May 2021
hough investment into nuclear energy continues – especially in emerging markets such as China – the sector is shrinking in Europe, with some key countries pursuing plans to phase out atomic power altogether. In January 2003, Belgium’s lawmakers agreed to stop any nuclear energy production within the country by 2025. Its seven existing reactors, all of which were opened between 1974 and 1985, are scheduled for decommissioning in the coming
years as the country moves ahead with a ‘100% renewable’ energy strategy. The federal government of Prime Minister Alexander De Croo, (a broad coalition of greens, liberals, Christian Democrats and socialists), has said it will stick to the 2025 phaseout deadline. However, De Croo himself has told journalists he is still ‘open to the idea’ of longer-term operations, should security of supply be a problem post-2025. A government report on the issue is scheduled for publication this November. Any delay would, unsurprisingly, be of concern to the two green parties in the coalition – the Ecolo and Groen parties. Samuel Cogolati, an Ecolo Parliamentary Deputy, tells Energy World: ‘Five out of the seven reactors will have to close by 2025 in any case because they are too old and no longer safe.’
Belgium decommissioning Jean-Pierre Clamadieu, President of French utility Engie, parent company of Belgium’s electricity provider Electrabel, said last November that prolonging the lives of the plants for 10 or even 20 years would cost up to €1bn given the equipment investment and regulatory compliance requirements. Moreover, he said the firm had not received government guidance on whether to start financing a potential extension of operations. Hostility from some politicians and environmentalists means that utilities are reluctant to even plan for a possible extension of nuclear operations, according to Paul Bossens, the President of pronuclear group 100TWh. Parisbased nuclear energy consultant Mycle Schneider, who opposes nuclear power, argues: ‘Engie/ Electrabel made it very clear that they are not interested in further lifetime extensions. Also, it is now technically too late to do upgrading work necessary for operation beyond 2025.’ In Schneider’s view, a change of government, even if the greens left the ruling coalition, would not
make much difference: ‘Any new government would have to pass a law in parliament to change [the 2025 phaseout]. However, if the operator does not wish any lifetime extensions, it is unrealistic to imagine any government forcing an operator into it.’ According to an Engie Belgium spokesperson, Electrabel is already preparing for the decommissioning of all its nuclear power plants, starting with Doel 3 and Tihange 2, in October 2022 and February 2023, respectively. The funds earmarked by the company for work amount to €13.8bn as of the end of last year. Of this total sum, €6.1bn has been reserved for the decommissioning and dismantling of the power plants themselves, and €7.7bn will go toward the final disposal of spent nuclear fuel. For the current government, the nuclear exit is not an end in itself, but a way of reaching its goal of developing more renewables and delivering a flexible, controllable energy supply. ‘Electricity prices will not rise as a result of plant closures – for consumers, families or businesses,’ Cogolati says. ‘This is a solemn engagement of the federal government.’ Cogolati tells Energy World that around €200mn per year from 2025 will be invested in developing 3.6 GW in additional generating capacity from all energy sources, compared with the €1.6bn needed ‘for just extending the plants for 10 years for 2 GW of nuclear.’ Replacing lost capacity Indeed, Belgium is already investing in alternative power production to replace the 6 GW of energy capacity represented by the country’s nuclear plants. For the time being, this replacement capacity will have to include fossil fuels, with national grid operator Elia saying the nuclear phaseout from 2022 to 2025 will require new gas-powered plants, as well as a significant growth in renewables and imported electricity. ‘The precise volume of replacement capacity has not yet been decided,’ says an Engie Belgium spokesperson. ‘But a
Nuclear energy
previous Elia study concluded 3.9 GW of new capacity would be needed.’ Belgium also plans to introduce a capacity remuneration mechanism (CRM). A first auction of energy projects is scheduled for November to ensure replacement capacity will be available by 2025. The government says the CRM is technology-neutral, so it can involve projects delivering gas or biomass-fired power plants, battery storage or any type of renewable energy. However, Matthias Meersschaert, spokesperson for the Belgian Nuclear Forum, says the CRM is only officially technology neutral, as Belgian nuclear capacity is excluded: ‘In practice it is expected that fossil-fuelled capacity will replace the current nuclear fleet,’ he says, warning of the expected increase in greenhouse gas emissions. Meersschaert said the decision to close nuclear operations after 40 years was a political not a technical one. The greens were needed to form a coalition government in 1999, and their condition for doing so was a commitment to end nuclear. He says the government could technically prolong nuclear plants’ lifetimes if it wanted to. ‘Extending operations is common worldwide – with extensions of 40 to 60 years in the
Netherlands and Switzerland, and the US even considering 80,’ Meersschaert says. Based on research from UK think-tank Ember, he believes that the scheduled nuclear phaseout would make Belgium the only EU country where carbon dioxide emissions from electricity production will increase – and dramatically – after 2025. Public opinion towards nuclear has also shifted, Bossens maintains. A January 2021 poll for Belgian TV and radio network RTL revealed roughly half the population opposes a nuclear phaseout, with only 25% in favour. ‘It’s a complete turnaround. Nuclear is no longer seen as dirty and dangerous,’ Bossens says. ‘The population now says we need nuclear to meet our climate goals.’ By 2030, half of Belgium’s electricity will be generated by renewables under any energy scenario, Meersschaert says: ‘Keeping nuclear open after 2025 is no barrier to the deployment of renewable energy in Belgium’. The end of German nuclear Germany’s nuclear phaseout, however, remains solidly on track, with no one doubting that the country’s last nuclear power plant will be shut down by the end of 2022. The federal elections in September are expected to see
a strong showing by the greens, making any u-turn on nuclear policy highly unlikely. The unprecedented effort of decommissioning the 17 reactors that once contributed 22% of Germany’s electricity mix began in 2011 after the political leadership in Berlin reacted to Japan’s Fukushima disaster that year by ordering a nuclear phaseout. Energy World spoke with PreussenElektra, a utility that is currently dismantling five reactors (Isar 1, Grafenrheinfeld, Stade, Unterweser and Würgassen), with three others (Grohnde, Brokdorf and Isar 2) still running. Production at Grohnde and Brokdorf will end by this December, whereas Isar 2 will be shut at the end of 2022. There’s little doubt that this phaseout process will reduce German electricity production in the short term. On 7 February, Grohnde broke the world record by passing the mark of 400 TWh of electricity generated by one plant in its lifespan, claims PreussenElektra. ‘From the experiences we gained through the dismantling of Stade, Unterweser and Würgassen, we are very confident that the remaining work will go ahead The Swiss government is smoothly,’ says Almut Zyweck, a executing a slow phaseout of its nuclear power stations, PreussenElektra spokesperson. including the Leibstadt plant ‘One key takeaway is that it is best on the River Rhine, at Aargau to begin with tackling the difficult Photo: Verpacker steps by first dismantling the pressure containers and the equipment in the cooling pools.’ Zyweck added that the increasingly tense discussions around climate change leave no mark on PreussenElektra’s phaseout plans, with the company remaining totally focused on the dismantling effort. Led by chancellor Angela Merkel’s Christian Democratic Union (CDU), Germany’s coalition government is committed to making renewables account for 60% of the mix by 2030. It plans to achieve this by doubling photovoltaic capacity and making land-based wind turbines increase output by one-third. The country’s last coal power plants are scheduled to be taken offline by 2038. In 2019 and 2020, Germany’s nuclear plant operators transferred their responsibilities for interim and end-storage to the stateowned Gesellschaft für Zwischenlagerung (BGZ) and Bundesgesellschaft für Endlagerung (BGE) respectively. BGE is tasked with finding an end storage location for the country’s nuclear waste by 2031. ‘This regulatory change means we are responsible for the Energy World | May 2021 19
Nuclear energy
packaging of radioactive waste, and we have not yet recorded any bottlenecks in passing on the waste to BGZ,’ Zyweck said. Slower Swiss approach Nuclear phaseout is also on track, albeit along a less-stringent timeline, in Switzerland, where four nuclear power plants currently generate up to 36% of the country’s electricity. The government decided in 2011 – following the Fukushima accident – not to replace any reactors, saying all plants would be closed by 2050. However, there is no final formal deadline. At that time, Bern halted the permit process for the planned construction of three new nuclear power plants. The decommissioning timetable is progressing in a typically pragmatic Swiss fashion. In December 2019, the Mühleberg plant, located 15 km from the Swiss capital, was closed after 47 years in operation by energy company BKW Group. The date of the shutdown reflected commercial considerations: the necessary safety measures and upgrades would have been too expensive and BKW opted to decommission. The dismantling will cost €865mn and waste
disposal will cost $1.4bn. Decommissioning began in January 2020 and will take 15 years to complete. The country’s remaining atomic power plants include its largest, Beznau, which has two reactors that generate some 6,000 GWh of electricity per year. While there are reports that the reactors could close by 2029, the operator insists that it has the right to continue generating energy as long as it is safe and economically possible to do so. The same applies to Switzerland’s third and fourth operating nuclear power plants – the 9,600 GWh Leibstadt, and the 8,000 GWh Gösgen – which have been projected to remain in operation until 2045 and 2040, respectively. However, no firm closure dates have been set. Under an Energy Strategy 2050 endorsed by Swiss voters in a 2016 referendum, these plants’ output will be replaced by more hydro power, which currently supplies about 60% of the country’s electricity, and renewables from solar, wind, biomass and geothermal sources, which are planned to increase from 5 TWh in 2017 to at least 11.4 TWh by 2035. However, another 2016
The scheduled nuclear phaseout would make Belgium the only EU country where carbon dioxide emissions from electricity production will increase – and dramatically – after 2025
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referendum vote blocked efforts by the Swiss Green Party to close all the plants by 2029. This was not welcomed by environmentalists. Matthias Lüthard, a spokesperson for another group, Switzerland’s Green Liberal Party, claims the government has made insufficient plans for phasing out its nuclear sector. ‘There is no sufficient insurance in case of an accident and the financial reserves are insufficient for the dismantling and disposal of nuclear power plants after decommissioning,’ he tells Energy World. ‘Even today, we are technically far from an ecologically and economically sustainable solution that could make nuclear waste significantly less harmful in the future.’ The problem of secure nuclear waste disposal has yet to be decisively solved by any country with a nuclear power sector. But the problem of climate change requires all of the low-carbon energy sources available. Though some European countries appear happy to dispose of fission power, others are dragging their feet, or pursuing expansion – and it’s not difficult to understand why. l
Renewables
HYDROGEN
Green hydrogen is on its way to becoming a reality
Affordable renewable power and economies of scale mean that cost competitive ‘green’ hydrogen could be a reality sooner than anticipated. Jennifer Johnson reviews recent data and project announcements to assess the market’s trajectory.
T
he hype around hydrogen as a fuel of the future is increasingly translating into investment decisions – and it’s about time. The first fuel cell prototype was built in 1889 by the German-born industrialist Ludwig Mond and his assistant, Carl Langer. Promising as the technology was, it would quickly be overshadowed by the cheaper and less intricate internal combustion engine. Over the course of the next century, interest in hydrogen would come in waves, usually when there was an oil price crisis, before receding again. Now it appears as though the latest and long-forecast boom in hydrogen technologies is finally, and irreversibly, underway. Energy companies of all stripes – from oil majors to utilities – have unveiled sizable hydrogen ambitions in the past year or so despite an uncertain economic outlook. In February 2020, Shell announced it had started feasibility work on what could ultimately be the largest green hydrogen project in the world, or at the very least in Europe. The plans will see the Dutch oil giant, and partners including Equinor, Gasunie and RWE, install 3–4 GW of offshore wind in the North Sea to power electrolysers located on the Netherlands’ northern coast. The project could be expanded to 10 GW of offshore wind
28 Energy World | May 2021
by 2040, with all power generated devoted solely to the production of ‘green’ hydrogen. Supplying electrolysers According to a report issued late last year by the International Renewable Energy Agency (IRENA), it is currently 2–3 times more expensive to make green hydrogen than its ‘blue’ counterpart, which comes from fossil fuels combined with carbon capture and storage. However, the agency believes that further falls in the price of renewables, combined with economies of scale in electrolyser manufacturing, mean that ‘green’ hydrogen could be cost-competitive with fossil fuels by 2030. Though low-cost renewable electricity is a necessary condition for costcompetitive green hydrogen, IRENA analysis emphasises that the investment costs for electrolysis facilities must also drop. For this to happen, today’s manufacturing capacity of less than 1 GW would have to grow beyond 100 GW in the next 10 to 15 years. Expansion this significant might sound like a tall order, but there are signs that real progress is being made. Earlier this year, manufacturer ITM Power opened the world’s first gigawatt-scale electrolyser factory in Sheffield, England. The facility will cut the cost of the firm’s electrolysers by
almost 40% over the next three years, according to its chief executive. In a recent funding round ITM Power raised enough money to build another massive factory that could be up to 2 GW in size. One of the company’s 20 MW electrolysers has recently been selected for a major green hydrogen scheme near Glasgow. Located adjacent to the Whitelee onshore wind farm, developer ScottishPower says the project will be powered by a combined solar and battery storage system with a total capacity of up to 90 MW. If local policymakers greenlight the planning application, the project could supply hydrogen to commercial markets by 2023.
ITM Power is to supply electrolysers to a green hydrogen project located next to Scotland’s Whitelee onshore wind farm, the largest of its kind in the UK Photo: ScottishPower
Charting hydrogen’s ascent According to energy research group BloombergNEF (BNEF)’s recent 1H 2021 Hydrogen Levelized Cost Update the falling costs of green hydrogen production mean that it will displace fossil-fuelled ‘blue’ and ‘grey’ hydrogen in the coming decades. Analysts found that hydrogen made entirely from renewables could be cheaper than fossil gas, on an energy-equivalent basis, by 2050 in 15 of the 28 markets it modelled – assuming scale-up continues on its current trajectory. These 15 countries accounted for one-third of global GDP in 2019. The
Renewables
report further claims that the costs of producing green hydrogen from renewable electricity should fall by up to 85% from today to 2050, leading to costs below $1/kg by 2050 in most modeled markets. ‘Such low renewable hydrogen costs could completely rewrite the energy map,’ says Martin Tengler, Lead Hydrogen Analyst at BloombergNEF. ‘It shows that in future, at least 33% of the world economy could be powered by clean energy for not a cent more than it pays for fossil fuels. But the technology will require continued government support to get there – we are at the high part of the cost curve now, and policy-supported investment is needed to get to the low part.’ BNEF’s cost predictions are some 17% lower than its previous forecasts for the middle of this century, and the falling costs of solar PV are the key driver behind this anticipated reduction. Analysts now believe that PV power will be 40% cheaper in 2050 than what they had thought only two years ago, driven by more automatic manufacturing, less silicon and silver consumption, higher photovoltaic efficiency of solar cells, and greater yields using bifacial panels. In all of the markets studied,
‘By 2030, it will make little economic sense to build ‘blue’ hydrogen production facilities in most countries, unless space constraints are an issue for renewables’ Martin Tengler, BNEF
green hydrogen should steadily become cheaper than both blue hydrogen (from fossil fuels with CCS) and even grey hydrogen made from methane. ‘By 2030, it will make little economic sense to build ‘blue’ hydrogen production facilities in most countries, unless space constraints are an issue for renewables,’ predicts Tengler. ‘Companies currently banking on producing hydrogen from fossil fuels with CCS will have at most ten years before they feel the pinch. Eventually those assets will be undercut, like what is happening with coal in the power sector today.’ Greening industry The majority of the world’s hydrogen is currently used in industry, including in the refining of oil and production of ammonia. There’s evidence that the mining sector is also interested in greening its operations through the deployment of hydrogen as a replacement for fossil fuels. For instance, French utility Engie has partnered with Chilean mining explosives manufacturer Enaex to study the feasibility of producing green ammonia. The proposed project would use 36 MW of solar energy to power a 26 MW electrolyser. The resulting hydrogen
would then be used to make ammonia, a key ingredient in ammonium nitrate, used in controlled explosions by miners. Meanwhile, mining giant Anglo American has been piloting the use of hydrogen in a forklift at one of its Chilean mining operations. Heavily polluting industries are naturally interested in using hydrogen to improve the environmental profile of their activities, thereby extending their economic lives in a decarbonising world. To this end, BP has partnered with Danish wind producer Ørsted to build a 50 MW electrolyser at the Lingen Refinery in north west Germany. The facility will be powered by energy generated at one of Ørsted’s North Sea wind farms, and the hydrogen will subsequently be used in BP’s Lingen oil refining operations. As of last summer, Wood Mackenzie estimates that less than 1% of total annual hydrogen production can be classified as green. Evidently, the sector still has a way to go before the cleanest form of hydrogen is ubiquitous. But the political momentum behind it shows no sign of slowing down and, better yet, this enthusiasm appears to be translating into project decisions. With any luck, hydrogen is here to stay this time. l
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