The project is called Mission H2 Power, and will support the decarbonization of SSE’s Keadby 2 Power Station in North Lincolnshire, which is powered by Siemens Energy’s SGT5-9000HL gas turbine.

The multi-million-pound co-investment will see Siemens Energy develop a combustion system for its SGT5-9000HL gas turbine capable of operating on 100% hydrogen, while maintaining the flexibility to operate with natural gas and any blend of the two.

This will see additional facilities constructed at Siemens Energy’s Clean Energy Centre in Berlin to allow testing of the technology for large gas turbines to take place.

Finlay McCutcheon, managing director of SSE Thermal, commented in a statement: “We know hydrogen-fired power stations will be an essential element of the energy mix in a net zero world and Mission H2 Power will help us accelerate their deployment through engineering excellence.

“…Our projects will be pivotal in providing flexible backup to renewables and while we still need to see a rapid acceleration in policy and deployment, the need for this technology is beyond question – it is a matter of when not if and this partnership can help us reach that destination as soon as possible.”

Darren Davidson, vice president of Siemens Energy UK&I, added: “We are living in a transformative time for the energy sector. Our HL-class gas turbine has set records for efficiency and power performance. This new collaboration is a significant step in reaching the point where large gas turbines can run on 100% hydrogen.”

Investment in Mission H2 Power aligns with SSE’s commitment to transition away from the use of unabated fossil fuels in electricity generation and accelerate hydrogen projects.

SSE is also working on the Keadby Next Generation Power Station project in partnership with Equinor, to ensure the plant is capable of running on either hydrogen or natural gas, or a blend of the two. This allows for flexibility in the event of delays to the hydrogen infrastructure.

Delivering low-carbon power stations will be essential to providing a clean power system in the UK, with the plants fulfilling a vital role as flexible back-up in a renewables-led system. Analysis from National Energy System Operator shows that around 7GW of low-carbon flexible power will likely be needed on the system by 2035, with around half of that capacity provided by hydrogen-fired power stations.

Originally published in Power Engineering International.

The LM6000 gas turbine is part of the order secured with ATCO Australia for four LM6000VELOX units.

The announcement was made during a signing ceremony at COP29 attended by Ramesh Singaram, president and CEO of Asia, Gas Power, GE Vernova together with The Hon Peter Malinauskas, premier of South Australia and John Ivulich, CEO and Country Chair, ATCO Australia.

The commissioning of the turbine is expected in early 2026 and will mark the first time a GE Vernova power plant project, at commercial scale, is powered by aeroderivative gas turbine combustion technology capable of operating on 100% hydrogen.

GE Vernova’s aeroderivative gas turbine solution will be powered by renewable hydrogen generated at the Whyalla complex, which will include one of the world’s largest hydrogen production and storage plants.

When completed, the 200MW Whyalla hydrogen facility will act as a new source of firming capacity, providing additional grid stability to the state when renewable sources are not not able to meet demand.

Eric Gray, CEO of GE Vernova’s Gas Power business commented in a statement: “GE Vernova has been investing over the years in R&D to advance the capabilities of its combustion systems to burn higher blends of hydrogen. We are proud to unveil our first 100 percent hydrogen-ready aeroderivative gas turbine solution to support our customers’ decarbonization goals while maintaining grid reliability, which requires the deploying of renewable and conventional power technology in tandem.”

According to John Ivulich, CEO and Country Chair, ATCO Australia, deploying this solution will ultimately support South Australia’s decarbonization journey and aligns with the state’s goals outlined in the government’s Hydrogen Jobs Plan.

Said Ivulich: “With more than 70 percent of energy generated from renewable resources, South Australia is set to become a global leader in producing and utilizing renewable hydrogen and we are delighted to be part of this project that can unlock decarbonization opportunities.”

GE Vernova’s portfolio includes over 120 gas turbines that have the capacity to operate or currently are operating on fuels that contain hydrogen, producing more than 530TWh of electricity over 8.5 million hours.

Originally published by Pamela Largue in Power Engineering International.

AEP has an agreement in place to secure up to 1 gigawatt (GW) of Bloom Energy solid oxide fuel cells for data centers and other large energy users who need to quickly power their operations while the grid is still being built out to accommodate demand. AEP calls it the largest utility fuel cell technology initiative in the nation.

“AEP worked with customers to develop a solution to power rapidly-growing demand in our service territory,” said Scott Blake, a spokesperson for AEP. “Fuel cells were identified as the right choice for our customers, and we have experience working with fuel cell installations previously. They are flexible and can be used in a variety of circumstances.”

Solid oxide fuel cells are typically used for auxiliary power, electric utilities, and distributed generation. Their advantages include high efficiency (a lower heating value of 60%), fuel flexibility, combined heat and power (CHP) capabilities, and hybrid/gas turbine cycle capabilities, per the U.S. Department of Energy (DOE). However, they also suffer from high temperature corrosion and breakdown of cell components, long start-up times compared to other forms of generation, and a limited number of shutdowns.

AEP expects commercial load to grow an average of 20% annually over the next three years, driven by data center development. The company is in the process of finalizing the first customer project agreements. Discussions are taking place with several other customers about using this technology to provide additional power to their sites while AEP makes the needed grid investments for the long term. All costs for the fuel cell projects will be covered by the large customers under a special contract.

“The rapid increase in energy demand is a challenge that AEP is tackling by finding innovative solutions to meet the unique needs of our customers,” said Bill Fehrman, AEP president and chief executive officer.

AEP has previous experience using Bloom Energy’s fuel cell technology to power customers. Initially, the projects will rely on natural gas, however, the technology has the potential to use hydrogen as an alternative fuel. 

“Fuel sources will be determined by the characteristics of the customer’s site, and while the fuel cells are capable of using hydrogen now, the availability of fuel will determine what is used,” said Blake.   

The customer-sited fuel cells will be required to meet the interconnection rules of the local operating company and will be designed to not send any energy back to the electric grid. AEP said it will work with regulators to secure the necessary approvals needed for these projects.

AEP is facing 15 GW of projected load growth from data centers by 2030, the utility said on its second-quarter earnings call over the summer. For perspective, AEP’s systemwide peak load at the end of 2023 was 35 GW. The utility serves 5.6 million customers in 11 states through its subsidiaries and has the country’s largest transmission system. According to a study published by EPRI in May, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used.

Last month, AEP Ohio filed a settlement agreement over a proposed data center rate structure that drew pushback from big tech names like Google, Amazon, Microsoft and Meta. This agreement, which is subject to review and approval by the PUCO, requires large new data center customers to pay for a minimum of 85% of the energy they say they need each month – even if they use less – to cover the cost of infrastructure needed to bring electricity to those facilities. The original proposed rate structure would have imposed a 10-year commitment to pay for a minimum of 90% of the energy customers say they need each month.

The agreement also creates a sliding scale that is meant to give small and mid-sized data centers more flexibility. It requires data centers to provide proof they are “financially viable” and able to meet those requirements, as well as to pay an exit fee if their project is canceled or unable to meet the obligations outlined in the electric service agreement contract. The requirements would be in place for up to 12 years, including a 4-year ramp-up period. The agreement also outlines a process to end the moratorium on new Central Ohio data center agreements.

The case began in May 2024, when AEP Ohio filed a proposal to reconcile the costs of infrastructure improvements required for Ohio’s growing data center industry. In direct testimony to Ohio’s Public Utilities Commission in August, several individuals, including consultants and tech employees, opposed AEP’s request, arguing that the new rates would be “discriminatory” and “unreasonable.”

This was one of the stand-out findings from the International Energy Agency’s latest report, Global Hydrogen Review 2024.

According to the report, a wave of new projects shows the continued momentum for low-emissions hydrogen despite challenges due to regulatory uncertainties, persistent cost pressures and a lack of incentives to accelerate demand from potential consumers.

The number of projects that have reached final investment decision has doubled in the past 12 months, which would increase today’s global production of low-emissions hydrogen fivefold by 2030. The total electrolyzer capacity that has reached final investment decision now stands at 20 gigawatts (GW) globally.

If all announced projects are realized worldwide, total production could reach almost 50 million tonnes [metric tons] a year by the end of this decade. However, this would require the hydrogen sector to grow at an unprecedented compound annual growth rate of over 90% between now and 2030, well above the growth experienced by solar PV during its fastest expansion phases.

Despite new project announcements, installed capacity for electrolyzers and low-emissions hydrogen volumes remain low as developers wait for clarity on government support before making investments. Uncertainty around demand and regulatory frameworks means most potential production is still in planning or early-stage development, with some larger projects facing delays or cancellations due to these barriers along with permitting challenges or operational issues.

“The growth in new projects suggests strong investor interest in developing low-emissions hydrogen production, which could play a critical role in reducing emissions from industrial sectors such as steel, refining and chemicals,” said IEA executive director Fatih Birol. “But for these projects to be a success, low-emissions hydrogen producers need buyers. Policymakers and developers must look carefully at the tools for supporting demand creation while also reducing costs and ensuring clear regulations are in place that will support further investment in the sector.”

The report highlights a gap between government goals for production and demand. Production targets set by governments worldwide add up to as much as 43 million tonnes [metric tons] per year by 2030, but demand targets only total just over a quarter of this, at 11 million tonnes [metric tons] by 2030.

Some government policies are already in place to stimulate demand for low-emissions hydrogen and hydrogen-based fuels. Examples, such as carbon contracts for difference and sustainable fuel quotas for aviation and shipping, are triggering action on the industry side, leading to an increase in signed agreements between producers and commercial consumers. However, the progress made in the hydrogen sector so far is not sufficient to meet climate goals, the report finds.

As a nascent sector, low-emissions hydrogen still faces technology and production cost pressures, with electrolyzers in particular slipping back on some of their past progress due to higher prices and tight supply chains. A continuation of cost reductions relies on technology development, but also optimizing deployment processes and moving to mass manufacturing to achieve economies of scale.

Cost reductions will benefit all projects, but the impact on the competitiveness of individual projects will vary. For example, hydrogen production via electrolysis in China could become cheaper than hydrogen produced from unabated coal by 2030, assuming the entire global electrolyzer project pipeline of around 520GW is realized.

Industrial hubs – where low-emissions hydrogen could replace the existing large demand for hydrogen that is currently met by production from unabated fossil fuels – remain an important untapped opportunity by governments to stimulate demand.

Originally published by Power Engineering International.

The project’s objective is to identify the primary challenges to siting, permitting and installation across the value chain from hydrogen production through end-use. The AI Assistant will be used for safe hydrogen (H2) handling and permitting and trainings focused on the safety for hydrogen development. 

GE Vernova will lead a project team named “H2Net”, including Clemson University, and Roper Mountain Science Center based in Greenville, SC, USA. GE Vernova will enter award negotiations valued in $1 million in US federal funding with the DOE to finalize the terms and the scope of the project.  

As part of this program, H2Net is expected to develop an AI Assistant that is trained specifically on the relevant, critical documents for safe H2 handling and permitting. The AI Assistant, called HySAGE, (Hydrogen Smart Assistant for Governance Execution), will be validated against requirements and lessons learned at GE Vernova’s Gas Turbine Manufacturing and Technology Center in Greenville, SC. HySAGE will aim to enable modeling capability and flexibility for incorporating the necessary codes and standards and environmental scenarios to increase the versatility and accuracy of the tool.

“These investments in clean hydrogen showcase the Administration’s commitment to making clean energy a win-win for all Americans—by contributing to a sustainable zero-carbon future, while boosting economic opportunities across the country,” said U.S. Secretary of Energy Jennifer M. Granholm. “These projects will work hand in hand with historic investments in the Hydrogen Hubs and electrolysis technologies to accelerate progress towards a clean hydrogen economy that will deliver good-paying, high-quality jobs and accelerate a renaissance of American manufacturing.”

GE, for example, has older units with more than 100,000 hours working with hydrogen fuels. Siemens Energy has been using hydrogen in various applications for over four decades.

As the power sector works to decarbonize, the idea of burning hydrogen in gas turbines and engines seems promising. When combusted alone, hydrogen does not produce CO2 emissions. Even hydrogen-natural gas blends reduce a plant’s carbon footprint and increase system flexibility.

However, the industry is years away from burning hydrogen at scale for decarbonization. The Institute for Energy Economics and Financial Analysis (IEEFA) said in a recent report that for at least the next 10 years, any “hydrogen-capable” gas-fired power plants are going to operate almost completely, if not entirely, using natural gas.

But the biggest obstacles to hydrogen firing in gas turbines are less technical and have more to do with the challenges of building new infrastructure and ramping up hydrogen supply.

Regarding supply, the U.S. produces about 10 million tons of hydrogen every year, nearly all of which is consumed in the petrochemical and fertilizer sectors. Any hydrogen co-firing in the power sector would require a lot of new production, even despite legislation offering significant incentives for hydrogen production in the U.S.

Just running the 15 largest natural gas combined-cycle (NGCC) plants with hydrogen would require doubling current U.S. production and would replace less than 10% of the electricity now generated annually from natural gas, IEEFA said in its report, Hydrogen: Not a solution for gas-fired turbines.

Hydrogen pilots and projects

Despite these challenges, a handful of U.S. natural gas-fired plant operators have made strides with hydrogen blending pilot studies in recent years.

This includes testing cofiring hydrogen at existing plants. Some operators have successfully tested using fuel blends made up of as little as 5% to as much as 44% hydrogen.

The 485 MW Long Ridge Energy Generation Project in Ohio burned a blend that included 5% hydrogen by volume in March 2022.

In September 2022, the New York Power Authority’s Brentwood power plant co-fired a blend of natural gas starting at 5% and reaching 44% hydrogen by volume in its 47 MW peaking unit. According to NYPA, the co-firing process showed a CO2 reduction of approximately 14% when hydrogen made up 35% of the natural gas stream.

In June 2022, Georgia Power’s McDonough power plant co-fired blend up to 20% hydrogen in one of its 233 MW natural gas turbines. The utility said the test released 7% fewer CO2 emissions compared with burning natural gas alone.

Other operators have turned to upgrading their turbines to use blends of natural gas and hydrogen.

Duke Energy plans to upgrade the 74 MW DeBary simple-cycle peaking plant in Florida to generate electricity solely from hydrogen.

The Los Angeles Department of Water and Power (LADWP) is considering upgrading Scattergood Generating Station Units 1 and 2 to have the capability of cofiring 30% hydrogen by December 2029, and potentially increasing to 100% if and when it is feasible to do.

Finally, there are three natural gas-fired plants under construction whose operators say will have the capability to co-fire hydrogen.

In Louisiana, Kindle Energy plans to build the 678 MW Magnolia Power Plant, which it expects to enter service sometime in 2025. Kindle Energy says thee plant could co-fire up to 50% hydrogen.

In Texas, Entergy is building thee 1,158 MW Orange County Advanced Power Station, which it expects to begin operating by mid-2026. We’ve previously reported that the plant, which would use Mitsubishi Power equipment, could burn up to 30% hydrogen.

However, the most notable new project might be an 840 MW plant being built by the Intermountain Power Agency in Utah. The project will replace an 1800 MW coal-fired plant. LADWP, which has the largest stake in the combined-cycle plant, said the new plant will be able to burn a mix of 30% hydrogen and 70% natural gas.

We’ve reported extensively on this new plant, which is tied to Advanced Clean Energy Storage Hub (ACES Delta Hub) in Delta, Utah. ACES is a large-scale clean hydrogen facility designed to produce, store, and deliver green hydrogen.

The hub will initially be capable of converting 220 MW of renewable energy into almost 100 metric tons per day of green hydrogen, which will then be stored in two massive salt caverns, having a storage capacity of more than 300 GWh of dispatchable clean energy.

The joint project is being led by Mitsubishi Power and Chevron U.S.A. Inc.’s New Energies Company (formerly Magnum Development). The hydrogen produced from electrolysis and then stored in the salt caverns will be fired in the 840 MW combined-cycle plant, which will be equipped with two Mitsubishi Power J-series gas turbines.

The project is expected to be ready in 2025.

The U.S. Energy Information Administration has a handy primer on the complete number of existing hydrogen pilots and upcoming projects.

Conclusion

Overall, while interest remains from power sector stakeholders in burning hydrogen in gas turbines, it is unclear how widespread this use case will be.

There are plenty of skeptics. IEEFA, for example, said terms like “hydrogen ready” or “hydrogen capable” amount to little more than marketing terms designed to obscure the challenges of hydrogen co-firing.

The institute also noted that along with supply challenges, no pipeline network exists to distribute the fuel to hydrogen-capable gas turbines being proposed in the U.S. IEEFA said building such a network would take years and cost billions of dollars, and the time and effort required for this buildout would slow the transition from fossil fuels.

In its final power plant rule targeting coal-fired and new natural gas-fired plants released earlier this year, the U.S. Environmental Protection Agency (EPA) removed hydrogen co-firing as a best system of emission reduction (BSER), instead leaning primarily on carbon capture and sequestration (CCS).

EPA said this was prompted by cost uncertainties and concerns shared during the public comment process leading up to the final rule.

“While the EPA believes that hydrogen co-firing is technically feasible based on combustion turbine technology, information about how the low-GHG hydrogen production industry will develop in the future is not sufficiently certain for the EPA to be able to determine that adequate quantities will be available,” the agency said.

The report, Fueling Up: How to Make U.S. Clean Hydrogen Projects Happen, draws upon the views and expertise of a range of sector specialists to explore what steps could be taken to realize clean hydrogen’s potential.

The report argues that the U.S. should boost exports to provide additional routes to market, bolster domestic manufacturing for hydrogen technologies, and prioritize ‘backbone’ infrastructure to reduce project risk.

The report says the Inflation Reduction Act and Bipartisan Infrastructure Law have generated commercial interest in American clean hydrogen projects. But the legislation, and implementation of those regulations, come with complexities and caveats that require navigation.

One issue is tax credits. Designed as incentives to encourage companies to produce clean hydrogen, helping them transition from early-stage development and planning to construction, the arrival of proposed IRS regulations on Section 45V in December 2023 have been considered too stringent by many, offering up more questions than answers, the report said.

For hydrogen to be considered ‘clean’ and eligible for credits it must meet three criteria: additionality, time matching, and deliverability. These criteria require that hydrogen facilities cannot draw power from a source more than three years older than the hydrogen project, electricity-producing hydrogen must be generated within the same hour as the hydrogen, and the electricity source and hydrogen facility must be in the same geographical area, as defined by the DOE’s transmission needs analysis.

Troutman Pepper says that as a result, many concerned developers and utilities are halting progress, warning that it will drive up costs and make it harder to get projects funded and constructed in this nascent sector, as they await further clarity from the IRS on its finalized rules.

Meanwhile, off-takers are asking for improved clean hydrogen certification standards to offer transparent reassurance that they are getting the product they think they are. To stimulate demand, the Biden Administration made $7 billion available to support seven regional clean hydrogen production hubs across the country.

However, businesses inclined to follow this route, such as chemical and metal producers, oil refineries, and transportation and utility companies, are feeling uneasy about the potentially ambiguous nature of hydrogen classifications, the report said. Faced with directives to reduce their environmental impact, businesses are struggling with a lack of visibility, guidance, and uniform certification to verify how green any available fuel actually is.

The report notes that more states could encourage greater uptake of clean hydrogen, similar to what numerous states previously did with regard to renewable portfolio targets. For instance, only California, Oregon, and Washington have introduced low-carbon fuel standards thus far. State-led commitments along these lines could provide clean hydrogen users with greater confidence to support the development of a robust domestic clean hydrogen market, the report said.

Beyond the domestic market, some commentators within the report argue there is an opportunity to establish the U.S. as a clean hydrogen exporter, particularly to Europe and Asia, including in the form of ammonia. Industries globally are under regulatory pressure to decarbonize. Many countries outside the U.S. face greater challenges in relation to their regional energy transition policies, making U.S. hydrogen a potentially attractive proposition, bringing in capital and off-take certainty from around the world, while developing a spot market for clean hydrogen and related products.

On U.S. soil, report commentators have encouraged the building out of U.S. manufacturing facilities for hydrogen technologies, while prioritizing nationwide ‘backbone’ infrastructure to reduce project risk. Bloomberg New Energy Finance recently reported that 68% of global electrolyzer manufacturing is in China. In the short-term, this represents a reassuring level of access to equipment, but in the longer-term, the federal government has committed to growing domestic production to counteract that reliance.

Equally, interviewees argued that the government needs to unlock investments to support infrastructure, helping producers store and move their product more efficiently and economically. The DOE recognized this challenge in its June 2023 National Clean Hydrogen Strategy & Roadmap, where it reported that between $2 billion and $3 billion of investment annually is needed in hydrogen infrastructure projects between 2023 and 2030 to enable the U.S. to achieve annual production of 10 million metric tons by 2030.

“When compiling this report, we found that most commentators and sector specialists agreed about the vast potential of clean hydrogen to become a highly useful non-fossil component of America’s energy mix,” said Mindy McGrath, a regulatory and finance Partner in the energy practice group at Troutman Pepper. “And it’s been encouraging to see government incentives and financial support acknowledging that potential in an effort to drive both production and demand.

“What is less clear at present is how these mechanisms and stimuli will play out in the real world. Regulators are justifiably concerned about doing things the right way. That said, if the rules surrounding the sector are too onerous or ambiguous it is going to stifle progress. Major energy businesses – developers, producers, utilities, and investors – are rightly wary of this uncertainty. In this report we look at why there needs to be a concerted effort to demystify complex regulatory matters, and why clear guidance is needed to create a cohesive framework of strategies to properly advance the sector.”

Fueling Up: How to Make U.S. Clean Hydrogen Projects Happen can be downloaded here.

The U.S. Department of Energy said the California Hydrogen Hub will receive an initial $30 million to begin its planning and design phase. The state will eventually receive up to $1.2 billion for the project that is a key part of the Biden administration’s agenda to slow climate change.

The administration in October selected seven regional hubs for the $7 billion program that will kickstart development and production of hydrogen fuel, with the goal of eventually replacing fossil fuels such as coal and oil with the colorless, odorless gas that already powers some cars and trains.

The hubs, which include projects in 16 states, will spur more than $40 billion in private investment and create tens of thousands of good-paying jobs, many of them union positions, President Joe Biden has said.

The president has called clean hydrogen essential to his vision of net-zero greenhouse gas emissions in the U.S. by 2050.

The projects will be based in California, Washington, Minnesota, Texas, Pennsylvania, West Virginia and Illinois. All but the California and Texas hubs include projects in multiple states. Pennsylvania has projects in two separate hubs.

Frank Wolak, president and CEO of the Fuel Cell & Hydrogen Energy Association, said the announcement is monumental because the Energy Department got through a rigorous competitive process to be at the point now where there are contracts and it’s able to fund the hubs.

The money will fund a major infrastructure program and invest in the future of clean energy, he added.

“It’s the beginning of really showing what the hubs are going to be doing,” he said. “They’re all unique. In the case of California, they’re undertaking projects for using hydrogen for the decarbonization of the hard-to-abate sectors in transportation, among other things. Transportation is a big portion of what they’re going to tackle.”

A hub is meant to be a network of companies that produce clean hydrogen and of the industries that use it — heavy transportation, for example — and infrastructure such as pipelines and refueling stations.

Hydrogen can be made in ways that yield little if any planet-warming greenhouse gases. The Energy Department says hydrogen, once produced, can generate power in a fuel cell, emitting only water vapor and warm air.

While electric utilities and developers use terms like “hydrogen-ready” or “hydrogen-capable” in their project plans, IEEFA said this is little more than marketing designed to obscure the challenges of hydrogen co-firing in gas turbines.

The biggest obstacles to hydrogen co-firing in gas turbines include building new infrastructure and ramping up supply, according to the Institute in Hydrogen: Not a solution for gas-fired turbines.

U.S. utilities and developers have announced myriad of “hydrogen-ready” projects over the last several years, ranging from technology demonstrations to large-scale commercial developments. But IEEFA said for at least the next 10 years, any “hydrogen-capable” gas-fired power plants are going to operate almost completely, if not entirely, using natural gas.

The institute said state regulators and potential project investors should scrutinize assertions that hydrogen gas will be widely used in natural gas-fired turbines.

Lack of supply

IEEFA noted the U.S. produces about 10 million tons of hydrogen every year, nearly all of which is consumed in the petrochemical and fertilizer sectors. Any hydrogen co-firing in the power sector would require a lot of new production, the institute said. Just running the 15 largest natural gas combined-cycle (NGCC) plants with hydrogen would require doubling current U.S. production and would replace less than 10% of the electricity now generated annually from natural gas, IEEFA said.

The report cited a 2022 demonstration where Long Ridge Energy tested a 5% hydrogen blend at its newly commercialized 485 MW combined-cycle plant in Ohio. While the demonstration was a success, the company told the U.S. Energy Information Administration (EIA) it burned 325,000 cubic feet of hydrogen during the tests, producing 17 megawatt-hours (MWh) of power.

IEEFA said the example underscores the enormous amount of hydrogen needed for even a small level of blending and the challenges of scaling even larger. According to EIA, the company has not used any hydrogen in the Long Ridge turbine since the 2022 demonstration.

Lack of pipeline infrastructure

The institute noted that no pipeline network exists to distribute the fuel to hydrogen-capable gas turbines being proposed in the U.S. IEEFA also said building such a network would take years and cost billions of dollars, and the time and effort required for this buildout would slow the transition from fossil fuels.

While the U.S. has a sprawling natural gas pipeline network, with approximately 305,000 miles of inter- and intrastate transmission lines, there are only roughly 1,600 miles of hydrogen-dedicated pipelines in the U.S. Virtually all the existing infrastructure is concentrated in Texas and Louisiana, where there is petrochemical and other industry activity.

Blending hydrogen into existing pipelines has been proposed as a possible alternative, but IEEFA said the latest research has raised more questions than answers about the technical and safety implications of introducing hydrogen into the system. In short, blending hydrogen into pipelines would weaken the steel, IEEFA said, potentially leading to cracks, leaks and complete failure.

Read the full report here.

The Phoenix (Performance Hydrogen Engine for Industrial and X) project, which is funded with almost €5 million ($5.4 million) by the German government, is aimed to generate the same electrical and thermal energy as currently available through natural gas CHP units in the higher power range of up to 2.5 MW.

When fueled by green hydrogen, this next-generation stationary energy plant, expected to be a first of its kind, should be able to run in a completely carbon-neutral manner.

“We are convinced that combustion engines will remain an essential part of the provision of a reliable energy supply during the energy transition,” said Dr Jörg Stratmann, CEO of Rolls-Royce Power Systems.

“We are making them climate-friendly with sustainable fuels. That’s why we at Rolls-Royce are investing in the development of next-generation hydrogen engines.”

The Phoenix project is being undertaken by a consortium including the sustainable mobile propulsion systems group at the Technical University of Munich, MAHLE Konzern, Fuchs Lubricants Germany GmbH, the German Federal Institute for Materials Research and Testing (BAM) and Robert Bosch AG.

The joint project is scheduled to run for three years to develop a technology concept that is sufficiently mature for use in a complete prototype engine.

Rolls-Royce already has developed a gas-powered combustion mtu engine which can use hydrogen as a fuel, but the Phoenix project will develop the technology for an even more efficient next generation hydrogen engine.

New developments from the partners include the injection system, the piston group and the ignition system, as well as a completely new lubricant.

Rolls-Royce reports that the German government as part of its power plant strategy, which includes the expansion of renewable energies, has decided in favor of building more gas-fired power plants to compensate for the variability of renewable resources – in particular, smaller, decentralized gas engine plants that can flexibly compensate for the fluctuating feed-in of wind and solar power to the grid, which varies depending upon weather conditions.

To reduce CO2 emissions, biogas gensets and, in some cases, the first gas engines converted for hydrogen are currently being used. But as soon as the availability of green hydrogen is ensured on a large scale, the technology of the hydrogen cogeneration plants promoted in the Phoenix project should be ready for use.

Originally published by Power Engineering International.