By: Felicity Bradstock View the original article here
There is great optimism around the future of green hydrogen, with many seeing it as a super-fuel that will replace oil-derived options, as well as be highly competitive with electric battery technology. However, we are far from achieving this ambition yet, mainly due to small-scale production operations and high costs. Many companies around the globe have plans to produce green hydrogen, but some are battling challenges that are slowing down the rollout of the clean fuel. Despite improvements in production processes, thanks to greater investment in the sector in recent years, the production and transportation costs of green hydrogen remain much higher than other fuels, including other types of hydrogen.
Producing grey or blue hydrogen, which is derived from fossil fuels, is viewed as relatively low cost, with many companies already relying on this fuel. Grey hydrogen is produced using natural gas. It undergoes a steam methane reforming (SMR) process, which breaks methane apart using high-pressure steam, which creates separate hydrogen, carbon monoxide, and carbon dioxide molecules. This process produces high levels of carbon dioxide, around 9 to 10 tons of CO2 for every ton of hydrogen. But it is also highly cost-effective, so long as natural gas prices remain stable. In July 2022, the cost of grey hydrogen was around $2 per kilo.
In contrast, green hydrogen production methods are more expensive. Green hydrogen is made using renewable energy sources to power an electrolysis process that separates hydrogen from water, producing just steam as a waste product. It is carbon neutral, making it highly attractive for companies looking to decarbonize. However, by July 2022, it cost around $4 to $5 a kilo, or even more, to produce green hydrogen. And some industry experts believe that the high cost of green hydrogen production isn’t going to fall any time soon.
Green hydrogen is viewed by many international agencies, such as the International Energy Agency (IEA) and the International Renewable Energy Agency (IRENA), as a solution to decarbonize ‘hard-to-abate’ sectors. As more governments and private companies around the globe pump funding into green hydrogen operations, there are high hopes that the production cost of green hydrogen to fall substantially, to as low as $0.5 per kilo. However, others believe it will be difficult to drive the cost to lower than $3 per kilo.
IRENA published two studies to drive green hydrogen production worldwide: Green Hydrogen: A Guide to Policy Making in November 2020, and Green Hydrogen Cost Reduction: Scaling up Electrolysers to Meet the 1.5°C climate goal in December 2020. These studies were aimed at encouraging governments and private companies to scale up production, aimed at driving down costs. However, the price of green hydrogen production so far remains elevated, at around 2 to 3 times the cost of grey hydrogen production, when gas prices are stable.
Nevertheless, progress has been seen thanks to greater funding into research and development, with the price of electrolysers falling by around 60 percent since 2010. According to IRENA, they could decrease by a further 40 percent in the short term and by as much as 80 percent in the long term. This cost reduction prediction relies on greater innovation in electrolysis technology to improve its performance, as well as scaling up manufacturing capacity, standardization, and growing economies of scale.
Another challenge to consider is the cost of transportation. Murray Douglas, the head of hydrogen research at Wood Mackenzie, stated that “Hydrogen is pretty expensive to move… “It’s more difficult to move than natural gas … technically, engineering wise … it’s just harder.” And Douglas is not the only one concerned about this. The U.S. Department of Energy (DoE) has reported challenges with green hydrogen including “reducing cost, increasing energy efficiency, maintaining hydrogen purity, and minimizing hydrogen leakage.” The DoE believes greater research is required to “analyze the trade-offs between the hydrogen production options and the hydrogen delivery options when considered together as a system.”
Companies worldwide are now considering the best locations for their green hydrogen production facilities. While there is great potential for the development of plants in Australia, North Africa, and the Middle East, these could be very far from their principal markets. Douglas highlighted the need for a dedicated pipeline, constructed between the producer and end-user if moving green hydrogen by pipe. Alternatively, green hydrogen could be transported as ammonia with nitrogen, which could be shipped and sold to consumers such as fertiliser producers. Otherwise, users would have to crack the ammonia back into nitrogen, which would increase costs and result in energy losses.
For green hydrogen to be as successful as everyone hopes, it will require significant investment to overcome these challenges. Jorgo Chatzimarkakis, the CEO of the industry association Hydrogen Europe, suggests the need for a certification system, to guarantee that any green hydrogen production was powered by renewable sources. Further, a well-researched delivery strategy needs to be developed to ensure that production facilities are adequately linked with green hydrogen markets. This has been seen in projects such as Cepsa’s green hydrogen corridor between southern and northern Europe.
While transportation costs are high, companies already understand how to move green hydrogen as they have been doing it the same way with natural gas for decades. But some are deterred by high costs. Therefore, the industry must drive down production costs to alleviate some of the pressure on transportation. Although the green hydrogen industry continues to face several major challenges, preventing a wide-scale deployment of the clean fuel, greater investment in the sector over the coming decades will likely fix many of these problems and allow for the deployment of global, large-scale green hydrogen production.
Regulators and policymakers must resist the temptation to overcommit to hydrogen for end uses where electrification will ultimately win out.
By: Dan Esposito and Hadley Tallackson View the original article here
This opinion piece is part of a series from Energy Innovation’s policy experts on advancing an affordable, resilient and clean energy system. It was written by Dan Esposito, senior policy analyst in Energy Innovation’s Electricity Program, and Hadley Tallackson, a policy analyst in the Electrification Program at Energy Innovation.
The Inflation Reduction Act has upended hydrogen economics, making “green” hydrogen — electrolyzed from renewable electricity and water — suddenly cost-competitive with its natural gas-derived counterpart.
On the supply side, electrolyzers can help utilities integrate renewables into the grid, speeding the clean electricity transition. On the demand side, electrolysis can cost-effectively decarbonize hydrogen production.
But the new hydrogen economics mean regulators and policymakers must be even more careful to avoid directing the fuel to counterproductive applications like heating buildings.
“Gray” hydrogen, which uses the highly-polluting steam methane reformation, or SMR, process, has long been the cheapest production method, trading around $1.50-2.00 per kilogram in the United States. In comparison, electrolyzed hydrogen costs about $4-8/kg without subsidies. The Inflation Reduction Act’s $3/kg incentive for zero-carbon hydrogen makes green hydrogen cheaper than gray, potentially spurring an electrolyzer boom.
To facilitate utilities connecting newly-cheap electrolyzers to the grid, regulators should set tariffs reflecting their flexibility value, empowering more bullish utility wind and solar resource procurement.
However, cheap hydrogen should not encourage its use in applications better served by direct electrification like buildings or transportation. Regulators should remain wary of gas utility proposals to blend hydrogen into pipelines, as they would achieve few emissions reductions before facing costly dead-ends while increasing threats to public safety. State policymakers should also use caution before directing public funds toward hydrogen light-duty refueling stations, as electric vehicles have substantial cost and performance advantages that risk stranding hydrogen vehicle infrastructure.
Instead, industrial consumers should use green hydrogen to decarbonize their gray hydrogen consumption for a cheaper, cleaner product.
The IRA’s clean hydrogen production tax credits
The Inflation Reduction Act offers a 10-year production tax credit for “clean hydrogen” production facilities. Incentives begin at $0.60/kg for hydrogen produced in a manner that captures slightly more than half of SMR process carbon emissions, assuming workforce development and wage requirements are met. The PTC’s value rises to $1.00/kg with higher carbon capture rates before jumping to $3.00/kg for hydrogen produced with nearly no emissions.
However, the IRA’s “clean hydrogen” definition includes upstream emissions, including methane leakage from natural gas pipelines. Since methane is a much more potent greenhouse gas than carbon dioxide, even small leaks significantly increase the carbon capture rate needed to qualify for different PTC tiers.
This suggests “blue” hydrogen produced from pairing SMR and carbon capture and sequestration technology won’t qualify for the highest PTC value. Even hydrogen produced via pyrolysis — which uses natural gas but has no process emissions — may be knocked into lower tiers with enough methane leakage.
Green hydrogen therefore has a $3/kg subsidy advantage over gray and at least a $2/kg advantage over blue. These subsidies will be lower in practice, as the 10-year PTC will be spread over the facilities’ 15-or-more year lifetimes, but they still shift the hydrogen economics paradigm.
The opportunity: Cleaning today’s gray hydrogen while boosting renewable integration
The Inflation Reduction Act makes clean hydrogen production very cheap, but hydrogen faces costs for transportation, storage and conversion to other compounds. The U.S. also lacks hydrogen-compatible pipelines, storage caverns, refueling stations, and equipment like consumer appliances.
The first best use for clean hydrogen is circumventing these mid- and downstream cost and infrastructure challenges. Namely, clean hydrogen can plug-and-play to replace today’s gray hydrogen production.
For example, ammonia facilities and oil refineries use 90% of U.S. annual hydrogen production. Electrolyzers sited nearby can opportunistically produce clean hydrogen to reduce facilities’ fuel costs and emissions.
The gray hydrogen replacement market is huge — 90% of 2021 U.S. utility-scale wind and solar electricity would be required to produce it all via electrolysis. Green hydrogen also has a 25% to 50% greater GHG emissions reduction impact when replacing gray hydrogen than natural gas.
This process can speed renewable energy deployment. Grid-connected electrolyzers can draw from renewables when electricity is cheap, helping finance them for power that would otherwise fetch low prices or be curtailed. When electricity prices rise, electrolyzers can ramp down, allowing the renewables to meet demand and keeping hydrogen production cheap.
The combination is a win-win: grid-connected, price-responsive electrolyzers help clean the industrial sector and power grid without committing to extensive new hydrogen-ready infrastructure and appliances. As U.S. renewables deployment accelerates, the demand for complementary green hydrogen may grow apace, including feeding an enormous clean ammonia export market.
The risk: Misallocating public funds for myopic projects
The Inflation Reduction Act’s clean hydrogen PTC is a massive incentive and can make many potential hydrogen end-uses look attractive. However, these propositions are often a mirage.
Clean hydrogen tax credits will reduce electrolyzer capital costs, helping unsubsidized green hydrogen production costs converge toward the cost of renewable electricity. However, since renewable electricity will always be an input to electrolysis, unsubsidized green hydrogen will never be cheaper than direct use of renewable electricity, even though the $3/kg credit is large enough to temporarily distort the market in hydrogen’s favor. By contrast, renewable energy subsidies are helping unsubsidized wind and solar become cheaper than fossil fuel power plants, as these resources’ costs are independent of each other.
Despite these dynamics, suddenly cheap hydrogen will amplify the fuel’s hype, inviting proposals for investing in hydrogen infrastructure and compatible end-use equipment. Such actions risk wasting time and money on research or infrastructure that will be underutilized or stranded once Inflation Reduction Act subsidies expire.
For example, gas utility plans to blend hydrogen with natural gas may be cost-effective with the subsidies, but they heighten safety and public health risks and aren’t long-term decarbonization strategies. By comparison, electric appliances like heat pumps and induction stoves use clean electricity approximately four times more efficiently than green hydrogen equivalents.
Other proposals may entail committing public funds to sprawling new infrastructure networks including pipelines and refueling stations to support hydrogen-powered fuel cell vehicles. Yet electric light-duty vehicles hold clear, insurmountable advantages that may be veiled by heavily subsidized hydrogen.
Hydrogen infrastructure proposals will sometimes be worthwhile. For example, geologic caverns for seasonal electricity storage can help clean the last 10% to 20% of the power grid, using green hydrogen to generate electricity when renewables and batteries are unavailable. Hydrogen can also be used as a feedstock or fuel for high-heat industrial processes. But in these cases, hydrogen’s advantage comes from filling a niche that direct electrification cannot, making its inefficiencies irrelevant.
Setting up for success
The IRA’s clean hydrogen tax credits can accelerate a reliable clean electricity transition while beginning to decarbonize industry — if applied judiciously.
Supporting a clean power grid will require incentivizing developers to connect electrolyzers to the grid rather than build standalone projects with co-located renewables, as only the former will allow utilities to benefit from electrolyzers’ flexible demand.
The U.S. Treasury should issue guidance clarifying how electrolytic hydrogen’s carbon intensity will be measured. Its framework should explicitly permit electrolyzers to connect to the grid, using collocated renewables, power purchase agreements, or potentially renewable energy credits to confirm they’re powered by renewables.
Regulators should direct electric utilities to set electrolyzer-specific tariffs, as current industrial tariffs may be mismatched with the flexibility value electrolyzers provide. They should also ease interconnection constraints and build more transmission, both of which can connect co-located renewables and electrolyzer projects to the grid. More grid-connected electrolyzers should then give regulators greater confidence to fast-track utilities’ renewable deployment schedules.
Industry consumers should explore contracts that allow clean hydrogen to replace some or all of their gray hydrogen, reducing costs and providing a cleaner product that may fetch higher prices from climate-conscious purchasers.
However, regulators and policymakers should steel their resolve against temptations to overcommit to hydrogen for end-uses where electrification will ultimately win out.
Research and development should focus on ways clean hydrogen can decarbonize hard-to-electrify sectors like aviation and shipping and boost long-duration electricity storage, rather than focusing on blending hydrogen into natural gas pipelines, using hydrogen for low-heat industrial processes, or designing hydrogen-capable consumer appliances. Limited state funds for commercialization should support electric infrastructure like electric vehicle charging stations and heat pumps, letting private companies take the risk for ventures like hydrogen refueling stations.
Together, these strategies can ensure the Inflation Reduction Act clean hydrogen tax credits maximize their value in reducing GHG emissions without inadvertently leading states and utilities down futile paths.
Green hydrogen has been in the news often lately. President-elect Biden has promised to use renewable energy to produce green hydrogen that costs less than natural gas. The Department of Energy is putting up to $100 million into the research and development of hydrogen and fuel cells. The European Union will invest $430 billion in green hydrogen by 2030 to help achieve the goals of its Green Deal. And Chile, Japan, Germany, Saudi Arabia, and Australia are all making major investments into green hydrogen.
So, what is green hydrogen? Simply put, it is hydrogen fuel that is created using renewable energy instead of fossil fuels. It has the potential to provide clean power for manufacturing, transportation, and more — and its only byproduct is water.
Where does green hydrogen come from?
Hydrogen energy is very versatile, as it can be used in gas or liquid form, be converted into electricity or fuel, and there are many ways of producing it. Approximately 70 million metric tons of hydrogen are already produced globally every year for use in oil refining, ammonia production, steel manufacturing, chemical and fertilizer production, food processing, metallurgy, and more.
There is more hydrogen in the universe than any other element—it’s been estimated that approximately 90 percent of all atoms are hydrogen. But hydrogen atoms do not exist in nature by themselves. To produce hydrogen, its atoms need to be decoupled from other elements with which they occur— in water, plants or fossil fuels. How this decoupling is done determines hydrogen energy’s sustainability.
Most of the hydrogen currently in use is produced through a process called steam methane reforming, which uses a catalyst to react methane and high temperature steam, resulting in hydrogen, carbon monoxide and a small amount of carbon dioxide. In a subsequent process, the carbon monoxide, steam and a catalyst react to produce more hydrogen and carbon dioxide. Finally the carbon dioxide and impurities are removed, leaving pure hydrogen. Other fossil fuels, such as propane, gasoline, and coal can also be used in steam reforming to produce hydrogen. This method of production—powered by fossil fuels—results in gray hydrogen as well as 830 million metric tons of CO2 emissions each year, equal to the emissions of the United Kingdom and Indonesia combined.
When the CO2 produced from the steam methane reforming process is captured and stored elsewhere, the hydrogen produced is called blue hydrogen.
Hydrogen can also be produced through the electrolysis of water, leaving nothing but oxygen as a byproduct. Electrolysis employs an electric current to split water into hydrogen and oxygen in an electrolyzer. If the electricity is produced by renewable power, such as solar or wind, the resulting pollutant-free hydrogen is called green hydrogen. The rapidly declining cost of renewable energy is one reason for the growing interest in green hydrogen.
Why green hydrogen is needed
Most experts agree that green hydrogen will be essential to meeting the goals of the Paris Agreement, since there are certain portions of the economy whose emissions are difficult to eliminate. In the U.S., the top three sources of climate-warming emissions come from transportation, electricity generation and industry.
Energy efficiency, renewable power, and direct electrification can reduce emissions from electricity production and a portion of transportation; but the last 15 percent or so of the economy, comprising aviation, shipping, long-distance trucking and concrete and steel manufacturing, is difficult to decarbonize because these sectors require high energy density fuel or intense heat. Green hydrogen could meet these needs.
Advantages of green hydrogen
Hydrogen is abundant and its supply is virtually limitless. It can be used where it is produced or transported elsewhere. Unlike batteries that are unable to store large quantities of electricity for extended periods of time, hydrogen can be produced from excess renewable energy and stored in large amounts for a long time. Pound for pound, hydrogen contains almost three times as much energy as fossil fuels, so less of it is needed to do any work. And a particular advantage of green hydrogen is that it can be produced wherever there is water and electricity to generate more electricity or heat.
Hydrogen has many uses. Green hydrogen can be used in industry and can be stored in existing gas pipelines to power household appliances. It can transport renewable energy when converted into a carrier such as ammonia, a zero-carbon fuel for shipping, for example.
Hydrogen can also be used with fuel cells to power anything that uses electricity, such as electric vehicles and electronic devices. And unlike batteries, hydrogen fuel cells don’t need to be recharged and won’t run down, so long as they have hydrogen fuel.
Fuel cells work like batteries: hydrogen is fed to the anode, oxygen is fed to the cathode; they are separated by a catalyst and an electrolyte membrane that only allows positively charged protons through to the cathode. The catalyst splits off the hydrogen’s negatively charged electrons, allowing the positively charged protons to pass through the electrolyte to the cathode. The electrons, meanwhile, travel via an external circuit—creating electricity that can be put to work—to meet the protons at the cathode, where they react with the oxygen to form water.
Hydrogen is used to power hydrogen fuel cell vehicles. Because of its energy efficiency, a hydrogen fuel cell is two to three times more efficient than an internal combustion engine fueled by gas. And a fuel cell electric vehicle’s refueling time averages less than four minutes.
Because they can function independently from the grid, fuel cells can be used in the military field or in disaster zones and work as independent generators of electricity or heat. When fixed in place they can be connected to the grid to generate consistent reliable power.
The challenges of green hydrogen
Its flammability and its lightness mean that hydrogen, like other fuels, needs to be properly handled. Many fuels are flammable. Compared to gasoline, natural gas, and propane, hydrogen is more flammable in the air. However, low concentrations of hydrogen have similar flammability potential as other fuels. Since hydrogen is so light—about 57 times lighter than gasoline fumes—it can quickly disperse into the atmosphere, which is a positive safety feature.
Because hydrogen is so much less dense than gasoline, it is difficult to transport. It either needs to be cooled to -253˚C to liquefy it, or it needs to be compressed to 700 times atmospheric pressure so it can be delivered as a compressed gas. Currently, hydrogen is transported through dedicated pipelines, in low-temperature liquid tanker trucks, in tube trailers that carry gaseous hydrogen, or by rail or barge.
Today 1,600 miles of hydrogen pipelines deliver gaseous hydrogen around the U.S., mainly in areas where hydrogen is used in chemical plants and refineries, but that is not enough infrastructure to accommodate widespread use of hydrogen.
Natural gas pipelines are sometimes used to transport only a limited amount of hydrogen because hydrogen can make steel pipes and welds brittle, causing cracks. When less than 5 to 10 percent of it is blended with the natural gas, hydrogen can be safely distributed via the natural gas infrastructure. To distribute pure hydrogen, natural gas pipelines would require major alterations to avoid potential embrittlement of the metal pipes, or completely separate hydrogen pipelines would need to be constructed.
Fuel cell technology has been constrained by the high cost of fuel cells because platinum, which is expensive, is used at the anode and cathode as a catalyst to split hydrogen. Research is ongoing to improve the performance of fuel cells and to find more efficient and less costly materials.
A challenge for fuel cell electric vehicles has been how to store enough hydrogen—five to 13 kilograms of compressed hydrogen gas—in the vehicle to achieve the conventional driving range of 300 miles.
The fuel cell electric vehicle market has also been hampered by the scarcity of refueling stations. As of August, there were only 46 hydrogen fueling stations in the U.S., 43 of them in California; and hydrogen costs about $8 per pound, compared to $3.18 for a gallon of gas in California.
It all comes down to cost
The various obstacles green hydrogen faces can actually be reduced to just one: cost. Julio Friedmann, senior research scholar at Columbia University’s Center on Global Energy Policy, believes the only real challenge of green hydrogen is its price. The fact that 70 million tons of hydrogen are produced every year and that it is shipped in pipelines around the U.S. shows that the technical issues of distributing and using hydrogen are “straightforward, and reasonably well understood,” he said.
The problem is that green hydrogen currently costs three times as much as natural gas in the U.S. And producing green hydrogen is much more expensive than producing gray or blue hydrogen because electrolysis is expensive, although prices of electrolyzers are coming down as manufacturing scales up. Currently, gray hydrogen costs about €1.50 euros ($1.84 USD) per kilogram, blue costs €2 to €3 per kilogram, and green costs €3.50 to €6 per kilogram, according to a recent study.
Friedmann detailed three strategies that are key to bringing down the price of green hydrogen so that more people will buy it:
Support for innovation into novel hydrogen production and use. He noted that the stimulus bill Congress just passed providing this support will help cut the cost of fuel cells and green hydrogen production in years to come.
Price supports for hydrogen, such as an investment tax credit or production tax credit similar to those established for wind and solar that helped drive their prices down.
A regulatory standard to limit emissions. For example, half the ammonia used today goes into fertilizer production. “If we said, ‘we have an emission standard for low carbon ammonia,’ then people would start using low carbon hydrogen to make ammonia, which they’re not today, because it costs more,” said Friedmann. “But if you have a regulation that says you have to, then it makes it easier to do.” Another regulatory option is that the government could decide to procure green hydrogen and require all military fuels to be made with a certain percentage of green hydrogen.
Green hydrogen’s future
A McKinsey study estimated that by 2030, the U.S. hydrogen economy could generate $140 billion and support 700,000 jobs.
Friedmann believes there will be substantial use of green hydrogen over the next five to ten years, especially in Europe and Japan. However, he thinks the limits of the existing infrastructure will be reached very quickly—both pipeline infrastructure as well as transmission lines, because making green hydrogen will require about 300 percent more electricity capacity than we now have. “We will hit limits of manufacturing of electrolyzers, of electricity infrastructure, of ports’ ability to make and ship the stuff, of the speed at which we could retrofit industries,” he said. “We don’t have the human capital, and we don’t have the infrastructure. It’ll take a while to do these things.”
Many experts predict it will be 10 years before we see widespread green hydrogen adoption; Friedmann, however, maintains that this 10-year projection is based on a number of assumptions. “It’s premised on mass manufacturing of electrolyzers, which has not happened anywhere in the world,” he said. “It’s premised on a bunch of policy changes that have not been made that would support the markets. It’s premised on a set of infrastructure changes that are driven by those markets.”
There are a number of green energy projects in the U.S. and around the world attempting to address these challenges and promote hydrogen adoption. Here are a few examples.
California will invest $230 million on hydrogen projects before 2023; and the world’s largest green hydrogen project is being built in Lancaster, CA by energy company SGH2. This innovative plant will use waste gasification, combusting 42,000 tons of recycled paper waste annually to produce green hydrogen. Because it does not use electrolysis and renewable energy, its hydrogen will be cost-competitive with gray hydrogen.
A new Western States Hydrogen Alliance, made up of leaders in the heavy-duty hydrogen and fuel cell industry, are pushing to develop and deploy fuel cell technology and infrastructure in 13 western states.
Hydrogen Europe Industry, a leading association promoting hydrogen, is developing a process to produce pure hydrogen from the gasification of biomass from crop and forest residue. Because biomass absorbs carbon dioxide from the atmosphere as it grows, the association maintains that it produces relatively few net carbon emissions.
Breakthrough Energy, co-founded by Bill Gates, is investing in a new green hydrogen research and development venture called the European Green Hydrogen Acceleration Center. It aims to close the price gap between current fossil fuel technologies and green hydrogen. Breakthrough Energy has also invested in ZeroAvia, a company developing hydrogen-fueled aviation.
In December, the U.N. launched the Green Hydrogen Catapult Initiative, bringing together seven of the biggest global green hydrogen project developers with the goal of cutting the cost of green hydrogen to below $2 per kilogram and increasing the production of green hydrogen 50-fold by 2027.
Ultimately, whether or not green hydrogen fulfills its promise and potential depends on how much carmakers, fueling station developers, energy companies, and governments are willing to invest in it over the next number of years.
But because doing nothing about global warming is not an option, green hydrogen has a great deal of potential, and Friedmann is optimistic about its future. “Green hydrogen is exciting,” he said. “It’s exciting because we can use it in every sector. It’s exciting because it tackles the hardest parts of the problem—industry and heavy transportation. It’s interesting, because the costs are coming down. And there’s lots of ways to make zero-carbon hydrogen, blue and green. We can even make negative carbon hydrogen with biohydrogen. Twenty years ago, we didn’t really have the technology or the wherewithal to do it. And now we do.”
The U.S. needs a massive green hydrogen industry to decarbonize its electricity, transportation and industrial sectors, and major investments and policy changes today to enable it to grow to its full potential in the decades to come.
So says a new report sponsored by major oil companies, automakers, hydrogen producers and fuel cell manufacturers pushing U.S. policymakers to follow the lead of the European Union in making a major commitment to building the infrastructure to grow its green hydrogen capacity.
The Roadmap to a U.S. Hydrogen Economy report forecasts that hydrogen from low-carbon sources could supply roughly 14 percent of the country’s energy needs by 2050, including hard-to-electrify sectors now dependent on natural gas such as high-heat industrial processes and manufacturing fertilizer.
Hydrogen to power fuel cells will also augment battery-powered vehicles in decarbonizing the transportation sector, particularly for vehicles requiring long ranges and fast refueling times such as long-haul trucks, said Jack Brouwer, a professor at the University of California at Irvine and associate director of the National Fuel Cell Research Center, in a Monday webinar introducing the report.
Meanwhile, wind, solar and nuclear power that might otherwise be forced to curtail generation when the power grid doesn’t need it could be used to electrolyze water to generate hydrogen that can be stored to power natural-gas-fired turbines needed for grid reliability or on-site fuel cells to maintain continuous power at data centers, hospitals and other critical sites, he said.
The report, prepared by consultancy firm McKinsey, is “agnostic” as to how this future hydrogen supply is generated, “as long as it’s low-carbon,” Brouwer said. Beyond electrolysis via zero-carbon electricity, that could include steam reforming of natural gas — the way most of today’s hydrogen supply is made — using carbon capture and storage to reduce its greenhouse gas impact, or employing less fully developed methods such as waste gasification, he said.
The U.S. already generates about 11.4 million metric tons of hydrogen per year, with an estimated value of about $17.6 billion. But reaching the report’s targets could drive about $140 billion per year in revenue and support 700,000 jobs by 2030, and about $750 billion per year in revenue and a cumulative 3.4 million jobs by 2050, it states.
The U.S. lags behind China, Japan and the European Union in infrastructure and research investments to reach this potential. Government and industry investment in hydrogen as an energy carrier adds up to $2 billion per year in Asia and the European Union, the report finds, while U.S. Department of Energy funding for hydrogen and fuel cells has ranged from approximately $100 million to $280 million per year over the last decade.
A roadmap for green hydrogen expansion
The report doesn’t set specific dollar targets for U.S. investment. But it highlights the need for capital to build the hydrogen production and transport infrastructure to carry it to end users, incentives to stimulate private-sector investment, codes and standards to regulate a growing supply chain, and research into still-nascent technologies.
It also lays out a phased approach for building on existing hydrogen use cases to expand to new ones. Experience with the roughly 25,000 fuel cell-powered forklifts in use in the U.S. will enable expansion to larger classes of vehicles, for example, and fuel cells being used for on-site power at data centers can serve as models for integrating hydrogen into large-scale generation.
Major challenges lie ahead of this growth, Brouwer said. To reach the report’s goals, the number of fuel cell vehicles will have to grow from today’s roughly 2,500 to nearly 1.2 million by 2030, and the number of fueling stations will have to expand from about 100 today to more than 4,300. And advances are needed to blend existing pipelines will be needed to expand its use.
But utilities across the country are relying on these kinds of advances to allow them to meet goals of zero carbon by 2050. One example is Gulf Coast utility Entergy’s work with Mitsubishi Power to blend hydrogen into its gas mix at its power plants and plans to convert an underground gas storage facility to hold hydrogen as part of its long-term decarbonization goals.
Former Energy Secretary Ernest Moniz said at Wood Mackenzie’s Power & Renewables conference last week that “federal and state incentives to build a few major regional hubs for hydrogen” will be a critical early step for proving the fuel’s cost-effectiveness as a decarbonization strategy. “We think we should not be sitting here thinking of hydrogen as something for the 2030s and 2040s — it is, but let’s also make it something for the 2020s,” Moniz said.
U.S. green hydrogen activity in the works
Andy Marsh, CEO of report sponsor Plug Power, noted Monday that the company’s hydrogen fuel cell-powered forklifts and distribution center vehicles used by customers like Amazon, Walmart, Home Depot and Lowe’s are using about 27 million tons of hydrogen per day, supplied by its more than 100 fueling stations across the country. It’s expanding into heavy-duty vehicles to serve ports in the U.S. and Europe, and into producing stationary fuel cells for data centers and distribution hubs.
Last week Plug Power signed a deal with Brookfield Renewable Partners to supply 100 percent renewable power for what Marsh described as a “gigafactory” it plans to build in an as-yet-undisclosed location. The factory will be capable of producing up to 60,000 fuel cells and about 500 megawatts of green hydrogen electrolyzers per year, he said.
Toyota, one of the first major automakers to commit to fuel cell vehicles with its Mirai sedan, is also planning to expand production of hydrogen-powered semitrucks now being tested at the ports of Los Angeles and Long Beach, Senior Engineer Jackie Birdsall said. Toyota sees the growth of light-duty fuel cell vehicle markets driving cost reductions through economies of scale, along with heavy-duty fuel cell vehicles increasing demand for hydrogen fuel production and distribution.
Dutch oil giant Shell, which is planning a gigawatt-scale, wind-power-driven hydrogen cluster in the Netherlands, is also building hydrogen fueling stations in Los Angeles to serve these ports’ fuel cell vehicle’s needs, said Wayne Leighty, the company’s hydrogen fuel business development manager. Shell is also investing heavily in EV charging businesses centered on battery-powered vehicles, but “hydrogen fuel cells and electric vehicles are quite complementary” for meeting different needs, rather than being mutually exclusive options for zero-carbon transportation, he said.
French industrial gas manufacturing giant Air Liquide is investing $150million into a renewable liquid hydrogen generation plant in Nevada set to generate 30 tons per day, or enough to supply 40,000 fuel cell vehicles, when it opens in 2022, said Karine Boissy-Rousseau, president of the company’s North American hydrogen energy and mobility business. It’s also investing about $40 million to renovate a hydrogen facility in Quebec, Canada to double its capacity to convert renewable hydropower and wind power to green hydrogen to 20 megawatts by year’s end, she added.