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Iraq Nuclear Power Plan targets eight reactors and 11 GW to ease blackouts, curb emissions, and support desalination, with financing via partners like Rosatom and Kepco amid OPEC-linked demand growth and chronic grid shortages.

Key Points

A $40B push to build eight reactors adding 11 GW, easing blackouts, cutting emissions, and supporting desalination.

✅ $40B, 20-year payback via partner financing

✅ Talks with Rosatom, Kepco; U.S. and France consulted

✅ Parallel solar buildout to meet 2030 demand

Iraq is working on a plan to build nuclear reactors as the electricity-starved petrostate seeks to end the widespread blackouts that have sparked social unrest.

OPEC’s No. 2 oil producer – already suffering from power shortages and insufficient investment in aging plants – needs to meet an expected 50% jump in demand by the end of the decade. Building atomic plants could help to close the supply gap, though the country will face significant financial and geopolitical challenges in bringing its plan to fruition.

Iraq seeks to build eight reactors capable of producing about 11 gigawatts, said Kamal Hussain Latif, chairman of the Iraqi Radioactive Sources Regulatory Authority. It would seek funding from prospective partners for the $40 billion plan and pay back the costs over 20 years, he said, adding that the authority had discussed cooperation with Russian and South Korean officials, as Iran-Iraq energy cooperation progresses across the sector.

Plunging crude prices last year deprived Iraq of funds to maintain and expand its long-neglected electricity system, though grid rehabilitation deals have been finalized to support upgrades. The resulting outages triggered protests that threatened to topple the government.

“We have several forecasts that show that without nuclear power by 2030, we will be in big trouble,” Latif said in an interview at his office in Baghdad. Not only is there the power shortage and surge in demand to deal with, but Iraq is also trying to cut emissions and produce more water via desalination — “issues that raise the alarm for me.”

Raising financing will be a major task given that Iraq has suffered budgetary crises amid volatile oil prices. Even with crude at about $70 a barrel now, the country is only just balancing its budget, according to data from the International Monetary Fund.

The government will also have to tackle geopolitical concerns around the safety of atomic energy, which have stymied nuclear ambitions elsewhere in the region, even as Europe's nuclear decline underscores broader energy challenges.

Nuclear power, which doesn’t produce carbon dioxide, would help Gulf states’ efforts to cut emissions as governments worldwide, including India's nuclear push to expand capacity, look to become greener. The technology would also allow them to earmark more of their valuable hydrocarbons for export. Saudi Arabia, which is building a test reactor, burns as much as 1 million barrels of crude a day in power plants during its summer months when temperatures soar beyond 50 degrees Celsius (122 Fahrenheit).

The Iraqi cabinet is reviewing an agreement with Russia’s Rosatom Corp. to cooperate in building reactors, Latif said. South Korean officials this year said they wanted to help build the plants and offered the Iraqis a tour of UAE nuclear reactors run by Korea Electric Power Corp. Latif said the nuclear authority has also spoken with French and U.S. officials about the plan.

Kepco, Rosatom
Kepco, as the Korean energy producer is known, is not aware of Iraq’s nuclear plans and hasn’t been in touch with Iraqi officials or been asked to work on any projects there, a company spokesman said Tuesday. Rosatom didn’t immediately comment when asked about an agreement with Iraq.

Even if Iraq builds the planned number of power stations, that still won’t be sufficient to cover future consumption. The country already faces a 10-gigawatt gap between capacity and demand and expects to need an additional 14 gigawatts this decade, Latif said.

With this in mind, Iraq plans to build enough solar plants to generate a similar amount of power to the nuclear program by the end of the decade.
Iraq currently boasts 18.4 gigawatts of electricity, including 1.2 gigawatts imported from Iran into the grid. Capacity additions mean generation will rise to as much as 22 gigawatts by August, but that’s well short of notional demand that stands at almost 28 gigawatts under normal conditions. Peak usage during the hot summer months of July and August exceeds 30 gigawatts, according to the Electricity Ministry. Demand will hit 42 gigawatts by 2030, Latif said.

The nuclear authority has picked 20 potential sites for the reactors and Latif suggested that the first contracts could be signed in the next year.

It won’t be Iraq’s first attempt to go nuclear. Four decades ago, an Israeli air strike destroyed a reactor under construction south of Baghdad. The Israelis alleged the facility, called Osirak, was aimed at producing nuclear weapons for use against them. Iraq suffered more than a decade of violence and upheaval after the 2003 U.S. invasion, which was also motivated by allegations that Iraq wanted to develop weapons.

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DOE CCUS Funding advances carbon capture, utilization, and storage with FEED studies, regional deployment, and CarbonSAFE site characterization, leveraging 45Q tax credits to scale commercial CO2 reduction across fossil energy sectors.

Key Points

DOE CCUS Funding are federal FOAs for commercial carbon capture, storage, and utilization via FEED and CarbonSAFE.

✅ $110M across FEED, Regional, and CarbonSAFE FOAs

✅ Supports Class VI permits, NEPA, and site characterization

✅ Enables 45Q credits and enhanced oil recovery utilization

The U.S. Department of Energy’s (DOE’s) Office of Fossil Energy (FE) has announced approximately $110 million in federal funding for cost-shared research and development (R&D) projects under three funding opportunity announcements (FOAs), alongside broader carbon-free electricity investments across the power sector.

Approximately $75M is for awards selected under two FOAs announced earlier this fiscal year; $35M is for a new FOA.

These FOAs further the Administration’s commitment to strengthening coal while protecting the environment. Carbon capture, utilization, and storage (CCUS) is increasingly becoming widely accepted as a viable option for fossil-based energy sources—such as coal- or gas-fired power plants under new EPA power plant rules and other industrial sources—to lower their carbon dioxide (CO2) emissions.

DOE’s program has successfully deployed various large-scale CCUS pilot and demonstration projects, and it is imperative to build upon these learnings to test, mature, and prove CCUS technologies at the commercial scale. A recent study by Science of the Total Environment found that DOE is the most productive organization in the world in the carbon capture and storage field.

“This Administration is committed to providing cost-effective technologies to advance CCUS around the world,” said Secretary Perry. “CCUS technologies are vital to ensuring the United States can continue to safely use our vast fossil energy resources, and we are proud to be a global leader in this field.”

“CCUS technologies have transformative potential,” said Assistant Secretary for Fossil Energy Steven Winberg. “Not only will these technologies allow us to utilize our fossil fuel resources in an environmentally friendly manner, but the captured CO2 can also be utilized in enhanced oil recovery and emerging CO2-to-electricity concepts, which would help us maximize our energy production.”

Under the first FOA award, Front-End Engineering Design (FEED) Studies for Carbon Capture Systems on Coal and Natural Gas Power Plants, DOE has selected nine projects to receive $55.4 million in federal funding for cost-shared R&D. The selected projects will support FEED studies for commercial-scale carbon capture systems. Find project descriptions HERE. 

Under the second FOA award, Regional Initiative to Accelerate CCUS Deployment, DOE selected four projects to receive up to $20 million in federal funding for cost-shared R&D. The projects also advance existing research and development by addressing key technical challenges; facilitating data collection, sharing, and analysis; evaluating regional infrastructure, including CO2 storage hubs and pipelines; and promoting regional technology transfer. Additionally, this new regional initiative includes newly proposed regions or advanced efforts undertaken by the previous Regional Carbon Sequestration Partnerships (RCSP) Initiative. Find project descriptions HERE. 

Elsewhere in North America, provincial efforts such as Quebec's and industry partners like Cascades are investing in energy efficiency projects to complement emissions-reduction goals.

Under the new FOA, Carbon Storage Assurance Facility Enterprise (CarbonSAFE): Site Characterization and CO2 Capture Assessment, DOE is announcing up to $35 million in federal funding for cost-shared R&D projects that will accelerate wide-scale deployment of CCUS through assessing and verifying safe and cost-effective anthropogenic CO2 commercial-scale storage sites, and carbon capture and/or purification technologies. These types of projects have the potential to take advantage of the 45Q tax credit, bolstered by historic U.S. climate legislation, which provides a tax credit for each ton of CO2 sequestered or utilized. The credit was recently increased to $35/metric ton for enhanced oil recovery and $50/metric ton for geologic storage.

Projects selected under this new FOA shall perform the following key activities: complete a detailed site characterization of a commercial-scale CO2 storage site (50 million metric tons of captured CO2 within a 30 year period); apply and obtain an underground injection control class VI permit to construct an injection well; complete a CO2capture assessment; and perform all work required to obtain a National Environmental Policy Act determination for the site.

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Geothermal Power Plant Risks include hydrogen sulfide leaks, toxic gases, lava flow hazards, well blowouts, and earthquake-induced releases at sites like PGV and the Geysers, threatening public health, grid reliability, and environmental safety.

Key Points

Geothermal Power Plant Risks include toxic gases, lava impacts, well failures, and induced quakes that threaten health.

✅ Hydrogen sulfide exposure can cause rapid pulmonary edema.

✅ Lava can breach wells, venting toxic gases into communities.

✅ Induced seismicity may disrupt grids near PGV and the Geysers.

If lava reaches Hawaii’s PGV geothermal power plant, it could release of deadly hydrogen sulfide gas. That’s the latest potential danger from the Kilauea volcanic eruption in Hawaii. Residents now fear that lava flow will trigger a meltdown at the Puna Geothermal Venture (PGV) power plant that would release even more toxic gases into the air.

Nobody knows what will happen if lava engulfs the PGV because magma has never engulfed a geothermal power plant, Reuters reported. A geothermal power plant uses steam and gas heated by lava deep in the earth to run turbines that make electricity.

The PGV power plant produces 25% of the power used on Hawaii’s “Big Island.” The plant is considered a source of clean energy because geothermal plants burn no fossil fuels and produce little pollution under normal circumstances, even as nuclear retirements like Three Mile Island reshape low-carbon options.

The Potential Danger from Geothermal Energy

The fear is that the lava would release chemicals used to make electricity at the plant. The PGV has been shut down and authorities moved an estimated 60,000 gallons of flammable liquids away from the facility. They also shut down wells that extract steam and gas used to run the turbines.

Another potential danger is that lava would open the wells and release clouds of toxic gases from them. The wells are typically sealed to prevent the gas from entering the atmosphere.

The most significant threat is hydrogen sulfide, a highly toxic and flammable gas that is colorless. Hydrogen sulfide normally has a rotten egg smell which people might not detect when the air is full of smoke. That means people can breathe hydrogen sulfide in without realizing they have been exposed.

The greatest danger from hydrogen sulfide is pulmonary edema; the accumulation of fluid in the lungs, which causes a person to stop breathing. People have died of pulmonary edema after just a few minutes of exposure to hydrogen sulfide gas. Many victims become unconscious before the gas kills them. Long-term dangers that survivors of pulmonary edema face include brain damage.

Hydrogen sulfide can also cause burns to the skin that are similar to frostbite. Persons exposed to hydrogen sulfide can also suffer from nausea, headaches, severe eye burns, and delirium. Children are more vulnerable to hydrogen sulfide because it is a heavy gas that stays close to the ground.

Geothermal Danger Extends Far Beyond Hawaii

The danger from geothermal energy extends far beyond Hawaii. The world’s largest collection of geothermal power plants is located at the Geysers in California’s Wine Country, and regulatory timelines such as the postponed closure of three Southern California plants can affect planning.

The Geysers field contains 350 steam production wells and 22 power plants in Sonoma, Lake, and Mendocino counties. Disturbingly, the Geysers are located just north of the heavily-populated San Francisco Bay Area and just west of Sacramento, where preemptive electricity shutdowns have been used during extreme fire weather. Problems at the Geysers might lead to significant blackouts because the field supplies around 20% of the green energy used in California.

Another danger from geothermal power is earthquakes because many geothermal power plants inject wastewater into hot rock deep below to produce steam to run turbines, a factor under review as SaskPower explores geothermal in new settings. A geothermal project in Switzerland created Earthquakes by injecting water into the Earth, Zero Hedge reported. A theoretical threat is that quakes caused by injection would cause the release of deadly gases at a geothermal power plant.

The dangers from geothermal power might be much greater than its advocates admit, potentially increasing reliance on natural-gas-based electricity during supply shortfalls.

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Heavy-Duty Truck Electrification is disrupting the aftermarket as diesel declines: fewer parts, regenerative braking, emissions rules, e-drives, gearboxes, and software engineering needs reshape service demand, while ICE fleets persist for years.

Key Points

Transition of heavy trucks to EV systems, reducing parts and emissions while reshaping aftermarket service and skills.

✅ 33% fewer parts; regenerative braking slashes brake wear

✅ Diesel share declines; EVs and natural gas slowly gain

✅ Aftermarket shifts to e-drives, gearboxes, software and service

Those who sell parts and repair trucks might feel uneasy when reports emerge about a coming generation of electric trucks.

There are reportedly about 33% fewer parts to consider when internal combustion engines and transmissions are replaced by electric motors. Features such as regenerative braking are expected to dramatically reduce brake wear. As for many of the fluids needed to keep components moving? They can remain in their tanks and drums.

Think of them as disruptors. But presenters during the annual Heavy Duty Aftermarket Dialogue are stressing that the changes are not coming overnight. Chris Patterson, a consultant and former Daimler Trucks North America CEO, noted that the Daimler electrification plan underscores the shift as he counts just 50 electrified heavy trucks in North America.

About 88% of today’s trucks run on diesel, with the remaining 12% mostly powered by gasoline, said John Blodgett, MacKay and Company’s vice-president of sales and marketing. Five years out, even amid talk of an EV inflection point, he expects 1% to be electric, 2% to be natural gas, 12% to be gasoline, and 84% on diesel.

But a decade from now, forecasts suggest a split of 76% diesel, 11% gasoline, 7% electric, and 5% natural gas, with a fraction of a percent relying on hydrogen-electric power. Existing internal combustion engines will still be in service, and need to be serviced, but aftermarket suppliers are now preparing for their roles in the mix, especially as Canada’s EV opportunity comes into focus for North American players.

“This is real, for sure,” said Delphi Technologies CEO Rick Dauch.

Aftermarket support is needed
“As programs are launched five to six years from now, what are the parts coming back?” he asked the crowd. “Braking and steering. The fuel injection business will go down, but not for 20-25 years.” The electric vehicles will also require a gear box and motor.

“You still have a business model,” he assured the crowd of aftermarket professionals.

Shifting emissions standards are largely responsible for the transformation that is occurring. In Europe, Volkswagen’s diesel emissions scandal and future emissions rules of Euro 7 will essentially sideline diesel-powered cars, even as electric buses have yet to take over transit systems. Delphi’s light-duty diesel business has dropped 70% in just five years, leading to plant closures in Spain, France and England.

“We’ve got a billion-dollar business in electrification, last year down $200 million because of the downturn in light-duty diesel controllers,” Dauch said. “We think we’re going to double our electrification business in five years.”

That has meant opening five new plants in Eastern European markets like Turkey, Romania and Poland alone.

Deciding when the market will emerge is no small task, however. One new plant in China offered manufacturing capacity in July 2019, but it has yet to make any electric vehicle parts, highlighting mainstream EV challenges tied to policy shifts, because the Chinese government changed the incentive plans for electric vehicles.

‘All in’ on electric vehicles
Dana has also gone “all in” on electrification, said chairman and CEO Jim Kamsickas, referring to Dana’s work on e-drives with Kenworth and Peterbilt. Its gasket business is focusing on the needs of battery cooling systems and enclosures.

But he also puts the demand for new electric vehicle systems in perspective. “The mechanical piece is still going to be there.”

The demand for the new components and systems, however, has both companies challenged to find enough capable software engineers. Delphi has 1,600 of them now, and it needs more.

“Just being a motor supplier, just being an inverter supplier, just being a gearbox supplier itself, yes you’ll get value out of that. But in the longhaul you’re going to need to have engineers,” Kamsickas said of the work to develop systems.

Dauch noted that Delphi will leave the capital-intensive work of producing batteries to other companies in markets like China and Korea. “We’re going to make the systems that are in between – inverters, chargers, battery management systems,” he said.

Difficult change
But people working for European companies that have been built around diesel components are facing difficult days. Dauch refers to one German village with a population of 1,200, about 800 of whom build diesel engine parts. That business is working furiously to shift to producing gasoline parts.

Electrification will face hurdles of its own, of course. Major cities around the world are looking to ban diesel-powered vehicles by 2050, but they still lack the infrastructure needed to charge all the cars and truck fleet charging at scale, he added.

Kamsickas welcomes the disruptive forces.

“This is great,” he said. “It’s making us all think a little differently. It’s just that business models have had to pivot – for you, for us, for everybody.”

They need to be balanced against other business demands, including evolving cross-border EV collaboration dynamics, too.

Said Kamsickas: “Working through the disruption of electrification, it’s how do you financially manage that? Oh, by the way, the last time I checked there are [company] shareholders and stakeholders you need to take care of.”

“It’s going to be tough,” Dauch agreed, referring to the changes for suppliers. “The next three to four years are really going to be game changes. “There’ll be some survivors and some losers, that’s for sure.”

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Advanced Traffic Light System for Geothermal Safety models fracture growth and friction with rock physics, geophones, and supercomputers to predict induced seismicity during hydraulic stimulation, enabling real-time risk control for ETH Zurich and SED.

Key Points

ATLS uses rock physics, geophones, and HPC to forecast induced seismicity in real time during geothermal stimulation.

✅ Real-time seismic risk forecasts during hydraulic stimulation

✅ Uses rock physics, friction, and fracture modeling on HPC

✅ Supports ETH Zurich and SED field tests in Iceland and Bedretto

The Swiss Earthquake Service and ETH Zurich want to make geothermal energy safer, so news piece from Switzerland earlier this month. This is to be made possible by new software, including machine learning, and the computing power of supercomputers. The first geothermal tests have already been carried out in Iceland, and more will follow in the Bedretto laboratory.

In areas with volcanic activity, the conditions for operating geothermal plants are ideal. In Iceland, the Hellisheidi power plant makes an important contribution to sustainable energy use, alongside innovations like electricity from snow in cold regions.

Deep geothermal energy still has potential. This is the basis of the 2050 energy strategy. While the inexhaustible source of energy in volcanically active areas along fault zones of the earth’s crust can be tapped with comparatively little effort and, where viable, HVDC transmission used to move power to demand centers, access on the continents is often much more difficult and risky. Because the geology of Switzerland creates conditions that are more difficult for sustainable energy production.

Improve the water permeability of the rock

On one hand, you have to drill four to five kilometers deep to reach the correspondingly heated layers of earth in Switzerland. It is only at this depth that temperatures between 160 and 180 degrees Celsius can be reached, which is necessary for an economically usable water cycle. On the other hand, the problem of low permeability arises with rock at these depths. “We need a permeability of at least 10 millidarcy, but you can typically only find a thousandth of this value at a depth of four to five kilometers,” says Thomas Driesner, professor at the Institute of Geochemistry and Petrology at ETH Zurich.

In order to improve the permeability, water is pumped into the subsurface using the so-called “fracture”. The water acts against friction, any fracture surfaces shift against each other and tensions are released. This hydraulic stimulation expands fractures in the rock so that the water can circulate in the hot crust. The fractures in the earth’s crust originate from tectonic tensions, caused in Switzerland by the Adriatic plate, which moves northwards and presses against the Eurasian plate.

In addition to geothermal energy, the “Advanced Traffic Light System” could also be used in underground construction or in construction projects for the storage of carbon dioxide.

Quake due to water injection

The disadvantage of such hydraulic stimulations are vibrations, which are often so weak or cannot be perceived without measuring instruments. But that was not the case with the geothermal projects in St. Gallen 2013 and Basel 2016. A total of around 11,000 cubic meters of water were pumped into the borehole in Basel, causing the pressure to rise. Using statistical surveys, the magnitudes 2.4 and 2.9 defined two limit values ??for the maximum permitted magnitude of the earthquakes generated. If these are reached, the water supply is stopped.

In Basel, however, there was a series of vibrations after a loud bang, with a time delay there were stronger earthquakes, which startled the residents. In both cities, earthquakes with a magnitude greater than 3 have been recorded. Since then it has been clear that reaching threshold values ??determines the stop of the water discharge, but this does not guarantee safety during the actual drilling process.

Simulation during stimulation

The Swiss Seismological Service SED and the ETH Zurich are now pursuing a new approach that can be used to predict in real time, building on advances by electricity prediction specialists in Europe, during a hydraulic stimulation whether noticeable earthquakes are expected in the further course. This is to be made possible by the so-called “Advanced Traffic Light System” based on rock physics, a software developed by the SED, which carries out the analysis on a high-performance computer.

Geophones measure the ground vibrations around the borehole, which serve as indicators for the probability of noticeable earthquakes. The supercomputer then runs through millions of possible scenarios, similar to algorithms to prevent power blackouts during ransomware attacks, based on the number and type of fractures to be expected, the friction and tensions in the rock. Finally, you can filter out the scenario that best reflects the underground.

Further tests in the mountain

However, research is currently still lacking any real test facility for the system, because incorrect measurements must be eliminated and a certain data format adhered to before the calculations on the supercomputer. The first tests were carried out in Iceland last year, with more to follow in the Bedretto geothermal laboratory in late summer, where reliable backup power from fuel cell solutions can keep instrumentation running. An optimum can now be found between increasing the permeability of rock layers and an adequate water supply.

The new approach could make geothermal energy safer and ultimately help this energy source to become more accepted, while grid upgrades like superconducting cables improve efficiency. Research also sees areas of application wherever artificially caused earthquakes can occur, such as in underground mining or in the storage of carbon dioxide underground.

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Power-to-gas converts surplus renewable electricity into green hydrogen or synthetic methane via electrolysis and methanation, enabling seasonal energy storage, grid balancing, hydrogen injection into gas pipelines, and decarbonization of heat, transport, and industry.

Key Points

Power-to-gas turns excess renewable power into hydrogen or methane for storage, grid support, and clean fuel.

✅ Enables hydrogen injection into existing natural gas networks

✅ Balances grids and provides seasonal energy storage capacity

✅ Supplies low-carbon fuels for industry, heat, and heavy transport

Last month Denmark’s biggest energy firm, Ørsted, said wind farms it is proposing for the North Sea will convert some of their excess power into gas. Electricity flowing in from offshore will feed on-shore electrolysis plants that split water to produce clean-burning hydrogen, with oxygen as a by-product. That would supply a new set of customers who need energy, but not as electricity. And it would take some strain off of Europe’s power grid as it grapples with an ever-increasing share of hard-to-handle EU wind and solar output on the grid.

Turning clean electricity into energetic gases such as hydrogen or methane is an old idea that is making a comeback as renewable power generation surges and crowds out gas in Europe. That is because gases can be stockpiled within the natural gas distribution system to cover times of weak winds and sunlight. They can also provide concentrated energy to replace fossil fuels for vehicles and industries. Although many U.S. energy experts argue that this “power-to-gas” vision may be prohibitively expensive, some of Europe’s biggest industrial firms are buying in to the idea.

European power equipment manufacturers, anticipating a wave of renewable hydrogen projects such as Ørsted’s, vowed in January that, as countries push for hydrogen-ready power plants across Europe, all of their gas-fired turbines will be certified by next year to run on up to 20 percent hydrogen, which burns faster than methane-rich natural gas. The natural gas distributors, meanwhile, have said they will use hydrogen to help them fully de-carbonize Europe’s gas supplies by 2050.

Converting power to gas is picking up steam in Europe because the region has more consistent and aggressive climate policies and evolving electricity pricing frameworks that support integration. Most U.S. states have goals to clean up some fraction of their electricity supply; coal- and gas-fired plants contribute a little more than a quarter of U.S. greenhouse gas emissions. In contrast, European countries are counting on carbon reductions of 80 percent or more by midcentury—reductions that will require an economywide switch to low-carbon energy.

Cleaning up energy by stripping the carbon out of fossil fuels is costly. So is building massive new grid infrastructure, including transmission lines and huge batteries, amid persistent grid expansion woes in parts of Europe. Power-to-gas may be the cheapest way forward, complementing Germany’s net-zero roadmap to cut electricity costs by a third. “In order to reach the targets for climate protection, we need even more renewable energy. Green hydrogen is perceived as one of the most promising ways to make the energy transition happen,” says Armin Schnettler, head of energy and electronics research at Munich-based electric equipment giant Siemens.

Europe already has more than 45 demonstration projects to improve power-to-gas technologies and their integration with power grids and gas networks. The principal focus has been to make the electrolyzers that convert electricity to hydrogen more efficient, longer-lasting and cheaper to produce.

The projects are also scaling up the various technologies. Early installations converted a few hundred kilowatts of electricity, but manufacturers such as Siemens are now building equipment that can convert 10 megawatts, which would yield enough hydrogen each year to heat around 3,000 homes or fuel 100 buses, according to financial consultancy Ernst & Young.

The improvements have been most dramatic for proton-exchange membrane electrolyzers, which are akin to the fuel cells used in hydrogen vehicles (but optimized to produce hydrogen rather than consume it). The price of proton-exchange electrolyzers has dropped by roughly 40 percent during the past decade, according to a study published in February in Nature Energy. They are also five times more compact than older alkaline electrolysis plants, enabling onsite hydrogen production near gas consumers, and they can vary their power consumption within seconds to operate on fluctuating wind and solar generation.

Many European pilot projects are demonstrating “methanation” equipment that converts hydrogen to methane, too, which can be used as a drop-in replacement for natural gas. Europe’s electrolyzer plants, however, are showing that methanation is not as critical to the power-to-gas vision as advocates long believed. Many electrolyzers are injecting their hydrogen directly into natural gas pipelines—something that U.S. gas firms forbid—and they are doing so without impacting either the gas infrastructure or natural gas consumers.

Europe’s first large-scale hydrogen injection began in eastern Germany in 2013 at a two-megawatt electrolyzer installed by Essen-based power firm E.ON. Germany has since ratcheted up the amount of hydrogen it allows in natural gas lines from an initial 2 percent by volume to 10 percent, in a market where renewables now outpace coal and nuclear in Germany, and other European states have followed suit with their own hydrogen allowances. Christopher Hebling, head of hydrogen technologies at the Freiburg-based Fraunhofer Institute for Solar Energy Systems, predicts that such limits will rise to the 20-percent level anticipated by Europe’s turbine manufacturers.

Moving renewable hydrogen and methane via natural gas pipelines promises to cut the cost of switching to renewable energy. For example, gas networks have storage caverns whose reserves could be tapped to run gas-fired electric generation power plants during periods of low wind and solar output. Hebling notes that Germany’s gas network can store 240 terawatt-hours of energy—roughly 25 times more energy than global power grids can presently store by pumping water uphill to refill hydropower reservoirs. Repurposing gas infrastructure to help the power system could save European consumers 138 billion euros ($156 billion) by 2050, according to Dutch energy consultancy Navigant (formerly Ecofys).

For all the pilot plants and promise, renewable hydrogen presently supplies a tiny fraction of Europe’s gas. And, globally, around 4 percent of hydrogen is supplied via electrolysis, with the bulk refined from fossil fuels, according to the International Renewable Energy Agency.

Power-to-gas is catching up, however. According to the February Nature Energy study, renewable hydrogen already pays for itself in some niche applications, and further electrolyzer improvements will progressively extend its market. “If costs continue to decline as they have done in recent years, power-to-gas will become competitive at large scale within the next decade,” says study co-author Gunther Glenk, an economist at the Technical University of Munich.

Glenk says power-to-gas could scale up faster if governments guaranteed premium prices for renewable hydrogen and methane, as they did to mainstream solar and wind power.

Tim Calver, an energy storage researcher turned consultant and Ernst & Young’s executive director in London, agrees that European governments need to step up their support for power-to-gas projects and markets. Calver calls the scale of funding to date, “not proportionate to the challenge that we face on long-term decarbonization and the potential role of hydrogen.”

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