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Siemens Energy and Rolls-Royce SMR announced a supply partnership that locks in Siemens Energy as “its global turbine systems partner” of conventional technology for future small modular reactors (SMRs).

Per the agreement, Siemens Energy will exclusively supply steam turbines and generators— with outputs ranging from 20 MW to 1,900 MW—and other auxiliary systems for Rolls-Royce SMR's planned Generation 3+ modular nuclear power plants. The company will support the entire turbine systems package, including design, manufacture, installation, and commissioning for a global fleet of factory-built SMR power plants.

"We are currently experiencing a global renaissance of nuclear energy,” said Karim Amin, a Siemens Energy Executive Board member. “Numerous countries are turning to nuclear technology to produce low-emission electricity, and small modular reactors will play a key role in this. Siemens Energy brings decades of experience in conventional equipment, while Rolls-Royce has the necessary implementation expertise. This perfect symbiosis enables us to shape the future of energy supply jointly. We are pleased to work with Rolls-Royce SMR on this exciting project."

The final contract, detailing all specifics, is expected to be completed by the end of 2025.

Rolls-Royce SMR is developing a "mini nuclear power plant" that relies on its standardized, modular design to be operational faster than traditionally built plants due to its standardized, modular design. Its pressurized water reactors are designed to achieve an electrical output of up to 470 MW.

“The turbine systems are a vital part of the Rolls-Royce SMR power plant, and we are delighted to be working with Siemens Energy, a global leader in energy systems who have significant experience and a proven track record in nuclear steam turbines,” said Chris Cholerton, Rolls-Royce SMR Chief Executive. “This partnership will unlock U.K. jobs and a range of manufacturing opportunities. We are delighted that Siemens Energy will support our capability and enhance our ability to deliver a global fleet of Rolls-Royce SMRs.”

Siemens Energy said that SMRs are a promising technology for the future of nuclear energy and a key factor in the energy transition's success. Compared to conventional nuclear power plants, they are:

Rolls-Royce SMR was also selected to deploy SMR units in the Czech Republic and down-selected for potential projects in the United Kingdom and Sweden.

 announced its supply agreement for Taiwan's 1,200-MW Kuo Kuang 2 power plant. It will supply a complete power island, including two SGT6-9000HL gas turbines, one SST6-5000 steam turbine, three SGEN6-2000P generators, and the Omnivise T3000 control system. The plant, with CTCI as its engineering, procurement, and construction partner, will support Taiwan’s phase-out of coal and nuclear while integrating renewable and low-carbon energy.

James Montgomery, Chief Design Engineer for the Rolls-Royce novel nuclear team, and John Mason, Systems Design and Integration Technical Specialist working at Rolls-Royce's Novel Concepts team, spoke to 

. Microreactors are compact, portable rectors that produce thermal energy, which can be used as heat or converted to electric power. Micro-reactors can be quickly deployed and installed, and when they utilize a responsive design concept, they can prevent overheating and require fewer components, fewer operators, and less maintenance.

 Q&A with Felix Aschendorf, Sales Director Nuclear at Siemens Energy.

 He discusses its role as Rolls-Royce’s “global turbine systems partner” for conventional technology for small modular reactors (SMRs), technical challenges, and nuclear trends.

Rolls-Royce SMR's planned Generation 3+ modular nuclear power plants will feature Siemens Energy's steam turbines, generators, and other systems. 

Siemens Energy to Supply Steam Turbines for Rolls-Royce SMR's Nuclear Power Plants

, Baker Hughes announced two partnerships—with Hanwha and Argent LNG—and a special chemicals award from ExxonMobil Guyana.

Argent LNG selected Baker Hughes to supply its liquefaction solutions, power generation equipment, and gas compression systems for its proposed LNG export facility in Port Fourchon, LA—set to deliver approximately 24 MTPA of LNG. Baker Hughes’s NMBL modular LNG solution powered by the LM9000 gas turbine will integrate iCenter digital solutions powered by Cordant to maximize availability, reliability, and operational efficiency. Baker Hughes will also provide multi-year services to support Argent LNG terminal operations.

“Today’s announcement is a further testament to the technology capabilities that we have built over the past 30-plus years in LNG. This collaboration with Argent LNG underscores our commitment to delivering advanced, best-in-class LNG solutions,” said Lorenzo Simonelli, Chairman and CEO of Baker Hughes. “As global energy demand continues to grow, we are committed to providing innovative technology solutions to the LNG industry, a key supplier of reliable and affordable energy to many countries around the world.”

Phase 1 construction is slated to start in 2026; commercial operations are expected by 2030. 

Baker Hughes, Hanwha Power Systems, and Hanwha Ocean signed an agreement to leverage Baker Hughes’ small-size gas turbine technology and Hanwha’s ammonia combustion system. The two companies agreed to create 100% ammonia combustion dual-fuel with natural gas small-size turbines suitable for marine applications, onshore and offshore applications, and electric generation and mechanical drive.

“Decarbonizing hard-to-abate industries and transportation is one of the most pressing but high-potential opportunities of our time,” said Alessandro Bresciani, Senior Vice President of Climate Technology Solutions at Baker Hughes. “We believe fuel switching to ammonia will play a key role in achieving significant emissions reductions across these sectors, and to realize this ambition, the industry needs more partnerships such as this. Together, we will continue to lead by example and take energy forward.”

This comes on the heels of Hanwha’s successful proof-of-concept test of its combustor with 100% ammonia as the fuel gas and Baker Hughes’ initial turbine feasibility studies in 2024. The target date to complete the full engine test with ammonia is by the end of 2027, after which the ~16-MW power range turbine will be commercially available for orders.

“We are very excited to be collaborating with Baker Hughes to deliver an innovative and efficient solution to enhance the adoption of ammonia as a fuel for the propulsion system for future vessels. This collaboration marks a significant turning point in accelerating the transition to low-carbon fuel propulsion in the global maritime industries,” said James Shon, senior executive vice president and head of Product Strategy and Technology at Hanwha Ocean.

ExxonMobil Guyana awarded Baker Hughes a specialty chemicals and related services award for its Uaru and Whiptail offshore greenfield developments in Stabroek Block.

The multi-year contract includes topsides, subsea, water injection, and utility chemicals for the Errea Wittu and Jaguar floating production, storage, and offloading (FPSO) vessels. These vessels are currently under development and are targeted to begin production in 2026 and 2027, respectively.

“ExxonMobil Guyana and Baker Hughes share a long history of supporting Guyana’s energy sector, and we look forward to working together to write its next chapter,” said Amerino Gatti, Executive Vice President of Oilfield Services & Equipment at Baker Hughes. “Our experience operating across the country’s energy supply chain and unmatched expertise in oilfield and industrial chemicals make Baker Hughes uniquely suited to support complex FPSO operations such as these.”

Uaru and Whiptail will include up to 20 drill centers and 92 production and injection wells. Each FPSO will have a capacity of 250,000 barrels per day.

At Baker Hughes Annual Meeting 2025, the company announced partnerships to support LNG, ammonia, and offshore greenfield developments.

Conference Coverage

Baker Hughes Announces Supply Partnerships, Special Chemicals Award

Wednesday morning’s keynote at POWERGEN 2025, 

The Role of Gas Turbines in the Clean Energy Transition,

 highlighted the rapid development of low-carbon fuel retrofits for gas turbines as representatives from the top gas turbine OEMs discussed the latest technological advancements, positioning gas turbines as key players in the clean energy transition.

Some key themes from this morning's keynote include:

 Advancements in hydrogen combustion technology for gas turbines.

 Gas turbines are positioned as a crucial technology for the energy transition, providing reliability and flexibility while cleaner energy solutions are scaled up.

 Significant R&D efforts are focused on developing advanced combustors, carbon-capture technologies, and alternative fuel capabilities.

 All presenters emphasized strategies and technologies to reduce the carbon footprint of gas turbine power generation.

 MHI has successfully developed 100% ammonia firing technology, and a partnership is working on an ammonia-based gas turbine.

Bobby Noble, Senior Program Manager, Gas Turbine R&D at EPRI, moderated the panel and introduced the panelists:

Jason Jermark, Vice President of Global Services Operations - Siemens Energy

Fabien Codron, Director, Carbon Solutions - GE Vernova

Aad den Elzen, Vice President of Power Generation and Strategic Growth - Solar Turbines

Benjamin Thomas, Director, Hydrogen Production - Mitsubishi Power Americas

Jeffrey Benoit, Vice President of Clean Energy Solutions - PSM - a Hanwha company

Despite some negative perceptions, Jermark said gas turbines can achieve decarbonization and are clean energy. And while hydrogen supply lags behind demand, gas turbines can bridge the gap until supply increases. Beyond hydrogen, there are several other alternative fuels, including syngas, ammonia, and biofuels, that can help decarbonize gas turbines.

Jermark listed several gas turbine benefits, including:

Coal-to-natural gas shift (reducing emissions)

Grid stabilization (essential for renewable integration)

Siemens Energy has several projects in the pipeline:

HyFlex Power Project uses electrolyzers to produce green hydrogen in France

Hillabee: Achieved a world record for hydrogen co-firing and blending, up to 38%

Jermark announced some exciting news at the keynote. The company is accelerating 100% hydrogen firing for Siemens' largest gas turbine. More to come! Siemens Energy is also developing a Sco2 oxy-combustion engine, a potentially game-changing technology for near-zero emissions.

100% hydrogen-fueled dry low NOx combustor

 based on micromixer technology for full-scale combustion, which we reported on earlier this year. He also discussed NZT Power, the world's first 

carbon-capture and combined-cycle plant equipped with exhaust gas recirculation

den Elzen said that Solar Turbines is pursuing decarbonization through several strategies:

Improvements in digital and operational efficiency.

Carbon capture, utilization, and storage (CCUS) technologies

“New energy challenges must be addressed with rapid deployment of power solutions,” den Elzen said. “They must also be addressed via modular gas turbine solutions for data centers and utilities, providing 500+ MW of power.”

He emphasized a focus on fuel flexibility, continuous operation, and reliability for mission-critical applications.

“MHI's overall strategy focuses on long-term validation and the development of products for the future,” Thomas said.

MHI conducts combustion testing at the Takasago Hydrogen Park, a facility that includes a gas turbine and a rig. Due to Japan's high hydrogen cost, MHI generates hydrogen onsite at Takasago Park using electrolyzers and solid oxide electrolyzer cells (SOEC). MHI plans to initiate operation with a 30% hydrogen blend on a JAC turbine within the next year and intends to test a 50% hydrogen blend soon after.

The Nagasaki Carbon Neutral Park serves as MHI's primary research and development hub where 100% clean ammonia firing technology was developed. This is where MHI also conducts testing on CCS technology, biomass utilization, and ammonia use in thermal power plants.

Benoit provided a brief history of gas turbine technology development and discussed advancements in fuel-flexible combustion systems. He emphasized that existing turbines can easily be modernized and future-proofed with advanced technology retrofits and upgrades to accommodate evolving energy demands and operator market conditions.

“PSM's FlameSheet combustor was originally designed and implemented for F-Class gas turbines based on requirements by Calpine, our owner at the time,” Benoit said. “The FlameSheet combustor system, developed and validated over the past decade at DLR (German Aerospace Research Center) test facility in Cologne, Germany, is today applied across dozens of OEM B-, E-, and F-class gas turbines.” It can operate on up to 100% hydrogen.

 entered into a joint development and collaboration agreement to develop carbon-free e-propulsion systems for Hanwha’s maritime business utilizing ammonia gas turbines. This collaborative effort will result in an ammonia-turbine power plant capable of utilizing 100% natural gas to 100% ammonia fuel while meeting the IMO Tier III NOx emissions standards without a selective catalytic reduction system.

Keynote panelists discuss the latest innovations in gas turbine combustion systems, carbon capture, hydrogen, ammonia, and more. 

OEMs Share Gas Turbine, Clean Energy Innovations at POWERGEN 

 has been a hotbed for collaborative announcements. Earlier today, the company announced 

partnerships to support LNG, ammonia, and offshore greenfield developments

. Further collaborations with Eden Geothermal, PETROVIETNAM, Microsoft, and NNPC/FIRST E&P were also announced.

To advance geothermal opportunities in the United Kingdom, Baker Hughes signed an agreement with Eden Geothermal Ltd. The company also signed a memorandum of understanding (MoU) to deploy integrated services with PETROVIETNAM, a Vietnamese oil and gas group, to advance drilling operations, plug and abandonment, and related services.

Expanding on its previous collaboration, Baker Hughes signed an MoU with Microsoft to further technical integration, align product development pipelines, and co-deliver solutions that use Cordant by Baker Hughes and Microsoft Azure. Both companies want to create new customer value by enabling advanced digital capabilities, scalability, and enhanced flexibility.

“This expanded collaboration with Microsoft underscores our shared commitment to innovation, sustainability, and solving critical customer challenges across the energy and industrial sectors,” said Aravind Yarlagadda, Senior Vice President of Industrial Solutions, Industrial & Energy Technology at Baker Hughes. “By deepening the integration of Cordant and Microsoft Azure and aligning our product and go-to-market strategies, together we can drive operational excellence and support customers in driving value at scale from their digital investments.”

 Cordant solutions built with Azure AI Foundry to optimize operations, improve predictive maintenance, enhance safety, promote energy efficiency, and drive innovation and growth.

 Aligning product pipelines to ensure that Cordant continuously evolves with Azure’s innovations.

 Align on comprehensive go-to-market strategies.

 Cordant solutions will be available in Azure Marketplace.

"By extending our collaboration with Baker Hughes, we are driving industry-specific innovation to help transform the energy and industrial sectors," said Darryl Willis, Corporate Vice President Energy and Resources Industry at Microsoft. "Integrating Cordant with Azure's capabilities enables our joint customers to improve safety and reliability and achieve greater operational performance, energy efficiency, and growth through AI-powered digital solutions."

Baker Hughes is deploying its integrated digital production optimization solution, Leucipa automated field production, offshore in Niger Delta, marking its first deployment in Sub-Saharan Africa.

"Leucipa is enhancing the oilfield to be smarter and more efficient, enabling our customers to maximize the value of their assets," said Amerino Gatti, Executive Vice President of Oilfield Services & Equipment at Baker Hughes. "Our collaboration will support the responsible development of energy resources needed in Sub-Saharan Africa for years to come."

The company’s agreement with NNPC Limited/FIRST Exploration & Petroleum Development Company (FIRST E&P) will utilize Leucipa’s workflows to optimize well performance and enhance efficiency by automating functions, including:

Leucipa helps oil and gas operators proactively manage production and reduce carbon emissions. It utilizes data and automates production processes to minimize inefficiencies, ensure environmentally sound operations, and assist customers in recovering millions of barrels.

During its Annual Meeting, Baker Hughes signed agreements with Eden Geothermal, PETROVIETNAM, Microsoft, and NNPC/FIRST E&P.

Baker Hughes Announces Collaborations for Geothermal Power, Drilling Ops, Tech Integration, Automated Field Production

The current landscape of non-lithium long-duration storage technologies continues to grow and change. On Tuesday morning at POWERGEN 2025, Megan Reusser, Technology Manager at Burns & McDonnell, shed some light on this ever-changing market in her session, 

Navigating the Current Landscape of Long-Duration Energy Storage (LDES) 

and highlighted the advantages and disadvantages of technologies in the space, such as:

Currently, legislation supports LDES, but the new administration may change that. The Office of Clean Energy Demonstrations (OCED) is funding five to 15 projects at $20 million each.

“To achieve net-zero emissions goals, different forms of energy storage are going to be required due to several factors,” Reusser said. “Number one is the intermittency of renewables. As we know, there is an increase when the wind is blowing or the sun is shining but having the energy storage in place to follow that can also help enhance the grid’s stability and reliability. So, really focusing those two things together in the form of energy storage. Decarbonization across industries is another factor as is energy cost optimization—storing when costs are low, selling when costs are higher. Energy storage could also help reduce the need for grid expansion by allowing power and access in remote areas.”

There are four main types of LDES: mechanical, thermal, electrochemical, and chemical. Each type of LDES technology has its own set of challenges and advantages.

 converts electrical energy into potential or kinetic energy. This category has many technologies under its umbrella, and Reusser said it’s really for the longer duration. Some examples include:

Compressed air solutions, which store air at high pressures (geology-based)

Liquid air solutions, which store air at cold temps but require a high energy demand

Mechanical LDES technologies are used for grid balancing, backup power, and industrial microgrids. Some challenges with mechanical LDES are its high capital expenditures (CapEX) and inefficiency compared to other forms of energy storage. Plus, it has geographical limitations.

 technologies store energy in the form of heat, including latent heat, sensible heat, and electrothermal. Heat is transferred to working fluids to produce steam via a turbine at a later point. Thermal LDES applies to industrial heating but not industrial power.

It is scalable for long durations and decarbonizes hard-to-abate sectors. Potential heat loss and higher CapEx are challenges.

 technologies include flow batteries, metal anode batteries, and static batteries—they may look like lithium batteries, but they have a different chemistry. There are 40 different chemistries of flow batteries. What makes it a flow battery and differentiates it from a static or lithium battery is electrolytes are stored in tanks and flow through the cells to create the current.

Flow batteries are good for integration with renewables. They are scalable, have long lifespans, and have a low risk of thermal runaway. However, costs can be high, and due to configurations—several tanks with pumps, etc.—they have a lower energy density, and it takes up more space to have the same amount of energy storage in comparison to lithium. It also has a lot of moving parts, so it will require regular maintenance for some of the pumps, valves, and other components. Also, batteries tend to struggle in low-temperature conditions.

 technology solutions are hydrogen, ammonia, or LNG. For example, you could use renewable power to create hydrogen and then store that hydrogen, and that could technically be your form of energy storage. The same goes for ammonia and LNG. This is a good fit if you’re more interested in utilizing the molecule rather than the electron, Reusser said. This works to transport fuel, in industrial processes, and energy export so that you’re moving the molecule and not the electron. They can also be used to decarbonize hard-to-abate sectors.

These technologies also have high energy density. Similar to thermal and mechanical LDES, they are complex systems, so you could have high CapEx, and you have to deal with storing and transporting the molecules.

Choosing the right type of energy storage depends on the use case and lifecycle. Reusser recommends assessing operating conditions and cycling frequency and evaluating CapEx and financial planning.

Megan Reusser of Burns & McDonnell said mechanical, thermal, electrochemical, and chemical LDES could help reduce the need for grid expansion, but each has its challenges. 

Navigating Long-Duration Energy Storage

With the resurgence of gas-fired power driven by the current and projected increase in electricity demand, carbon-capture projects may serve to keep decarbonization initiatives on track into the future. At POWERGEN 2025, Kevin Lauzze, Senior Vice President of Sargent & Lundy, presented 

Lessons Learned from Carbon-Capture Pilot Projects

, outlining the advantages and risks of carbon-removal pilots prior to market entrance.

Lauzze stressed the importance of pilot projects in advancing carbon-capture technologies, but many stall during development or fail to reach the demonstration phase entirely. Based on his company’s experience, he provided a comprehensive how-to on flexible design, scale-up challenges, equipment sourcing, and budget planning pitfalls.

“The issue is greenhouse gases and the greenhouse gas effect,” said Lauzze. “Over the last handful of years, as we’ve emitted more greenhouse gases, we’ve amplified this. The gases are trapping more heat and making the Earth warmer. Greenhouse gases are comprised of multiple things, but primarily CO

, with most emissions coming from transportation, electricity generation, and industrial activities.”

 problem, he claims that the pollutant is here to stay with natural gas’ long-term necessity; thus, carbon-capture pilot projects will remain an important factor in continuing decarbonization efforts as more gas comes online. According to Lauzze, data centers are a two-fold driver behind carbon-capture growth and increasing gas integration.

Putting aside the immense power requirements, AI data centers will spur carbon-capture growth because “the people buying this power have very specific time-based sustainability goals,” said Lauzze. “Google wants a 50% CO

 reduction by 2030; Amazon wants net-zero by 2040; and Microsoft wants to be carbon-negative by 2030. This is what’ll drive the market.”

In a typical pilot, the Technology Readiness Level (TRL) lies around 6 or 7. At TRL 6, the complete prototype system is built and demonstrated in an applicable environment that resembles a future operational scenario; however, this version may not feature full system integration. At TRL 7, this prototype is demonstrated in a fully operational environment.

Sargent & Lundy has assisted companies in completing pilots at TRL6/7, and Lauzze provides specific examples: “The first one is at a Calpine facility in California using ION’s technology. It captures 10 tons of CO

 per day with an ION amine solvent. The unique aspect is its modular construction; it isn’t very big, but amine systems don’t save on height, instead on the diameter of the system. These 100-feet-tall modules were assembled in Texas and then shipped to California, but this caused a real challenge for this project.”

The next project for MTR Carbon Capture uses a membrane system to capture up to 150 tons of CO

 per day: “This is a good example of a project that hasn’t been tested at a larger scale, so a pilot is really important to help figure out optimization, failures, and costs,” said Lauzze. “One of the bigger challenges is that it’s located in Wyoming and needed a building. If you’re doing a pilot, you’ll want a controlled environment to perform testing and optimization without worrying about the cold. Consider where you build the pilot.”

He rounded out the pilot project examples with Chart Industries’ Sustainable Energy Solutions, which is demonstrating its carbon-capture technology at a cement plant. The system—about to be installed—will capture approximately 30 tons of CO

“Pending the decisions of our current administration, there are currently many opportunities for the Department of Energy (DOE) to fund these projects,” said Lauzze. “Four projects have already been announced by the DOE and are underway, and people can apply for pilot project funding. The DOE is committed to funding these types of projects to surpass challenges associated with obtaining a TRL. There is about $70 million in project development funding with the DOE.”

Outside of DOE funding, there’s not much available for those willing to test their systems.

Despite the available funding for carbon-capture pilots, technology providers need certain guarantees to continue projects. These system developers are hesitant, according to Lauzze, to demonstrate their technologies on alternative generation sources or those phasing out, such as coal. Carbon-capture providers may not be willing to take risks on combined-cycle assets either, as there’s not much data on this technology combination.

Lauzze said that all successful carbon-capture pilots reduce three kinds of risk: technology, deployment, and operational risks. Minimizing these risks during a pilot contributes to technology commercialization and market entrance, especially considering the role investors serve to put their money and reputation behind a technology for anticipated success.

He outlined several additional considerations for pilot project developers:

Temporary vs. permanent installations must be evaluated, as it heavily impacts cost

The test plan should be completed pre-FEED

Pilots should embrace using smaller or used equipment, as some industrial vendors may not prioritize these orders, leading to longer wait times

Demonstration equipment can be built from scratch

Pilot projects should closely (or exactly) replicate the full-scale commercial model or operating scenario

Lastly, “The whole design depends on agreement,” said Lauzze. “As you enter a pilot, make sure all the stakeholders agree on its purpose. It’ll save on later changes and prevent confusion during field deployment. If you do this up front, it’ll go a long way.”

Kevin Lauzze of Sargent & Lundy discusses the rise of carbon-capture pilot projects and how technologies can successfully enter the market.

Araceli Garcia Diez

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