The department selected investment firm Brookfield Asset Management to develop and operate the data center at the government-owned Paducah Gaseous Diffusion Plant. In March, the department announced a similar project at its Portsmouth Gaseous Diffusion Plant in Ohio.

Both are undergoing extensive cleanup, decontamination and decommissioning after decades of fueling the nation’s nuclear weapons and power plants. The project is in line with the Trump administration’s efforts to make artificial intelligence superiority over China a top national security and economic priority.

The federal government is transforming former DOE sites into “engines of innovation and economic growth” to “ensure the United States wins the A.I. race,” Energy Secretary Chris Wright said in a statement last week.

“There will be a lot of new natural gas power plants, a large data center, thousands of jobs and tens of billions of dollars of investment in rural western Kentucky,” Wright said on the Fox News show “Fox & Friends.”

Earlier in July, the Department of Energy said it had picked engineering contractor Amentum to negotiate a lease to develop an AI data center and on-site power plant at South Carolina’s Savannah River Site, a massive complex where the federal government once produced materials used in nuclear weapons, primarily tritium and plutonium-239.

Real estate, energy and data center services are cornerstones in the investment portfolio of New York-headquartered Brookfield, which reports that it has more than $1 trillion in assets under management.

A Brookfield spokesperson estimated that 30% of the $100 billion in spending would go toward construction of the data center and power components, with the rest of the money being spent on the equipment in the data centers, including servers, routers and semiconductor chips.

Discussions were ongoing with commercial partners to use the data center space, Brookfield spokesperson Simon Maine said.

Other partners in the Paducah project are power generation and transmission giant NextEra Energy and local utilities.

Florida-based NextEra Energy will build and own the power generation components, which are to include 2 gigawatts of natural gas-fired generation, upgrades to transmission networks and 2.6 gigawatts of battery energy storage to support a new 1.8 gigawatt AI data center campus, the department said.

The plant would be the largest gas-fired power plant in Kentucky. A single gigawatt, according to a general industry standard for utilities, can power about 750,000 homes.

A power service agreement must be approved by state utility regulators, and excess electricity would be delivered to the regional grid. Construction was expected to be complete in 2031, the department said.

Cleanup is continuing at the roughly 3,550-acre Paducah plant site, which was on a list of 16 federal sites released last year as locations where the department could invite technology companies to build data management and storage capacity.

It shut down in 2013 and the gaseous diffusion process to enrich uranium is considered obsolete.

The department has projected that cleanup at the Paducah site would be completed in 2065 at a cost of about $17 billion, including demolishing buildings, disassembling uranium converters, removing refrigerant and treating a large plume of groundwater contamination.

In the meantime, the department is working on plans to provide some of the uranium waste being stored for decades at the Paducah site to a pair of companies seeking to use newer technologies to re-enrich it for use in power plants.

Group raises questions about projects

A newly formed group called Protect McCracken County has raised questions about the uranium enrichment and data center projects, saying that the work is being carried out beside a river that 5 million people downstream drink from without an independent study of the impact.

Byron Gary, a senior attorney for the environmental and public health advocacy group Kentucky Resources Council, said any plans to develop the contaminated Paducah site or to withdraw water from the water table underneath it must be carefully executed.

He said the construction of a such a large gas-fired power plant — which emits planet-warming greenhouse gases — would have implications for climate change and that his organization would want to be certain that regular ratepayers are not forced to subsidize the power plants and transmission upgrades there.

Gary also said his organization will want to make sure that the Department of Energy does not circumvent permitting processes as a way to get around environmental protection laws.

“There shouldn’t be a justification to get around that and end up potentially dumping a lot more burden on a rural community that can’t afford it,” Gary said.

The next big baseload power plant may not rise on a riverbank or coastal inlet. It may sit on a four‑acre pad in the high desert, quietly punching holes six miles deep into basement rock and pulling out heat above 750°F (400°C).

As data centers and EV chargers devour megawatts (MW), a new class of geothermal developers aims to tap an energy resource blanketing every continent: superhot rock.

Conventional geothermal only generates about 16 gigawatts (GW) worldwide because developers historically hunted rare locations with hot water and open fractures. As I described at the Great Transformation event recently in Bend, Oregon, “superhot” geothermal turns up the volume.

New companies (including mine) are drilling hotter and deeper than conventional projects, into rock heated to 300–500°C, to create our own underground reservoirs. This promises firm power, compact footprints, and a talent pipeline straight from the oil patch. Engineers are finally cracking the drilling challenge that has kept most of that heat out of reach — until now.

The resource under our feet

If you picture Earth as an apple, conventional geothermal barely scratches the skin. But our planet stores an almost absurd quantity of heat. Even that thin layer holds enough heat to power civilization for tens of thousands of years. The upper 6–12 miles (10–20 kilometers) of crust contain orders of magnitude more energy than all known fossil reserves combined.

Historically, developers only tapped that resource where geology cooperated, chasing locations with a lucky overlap of steep geothermal gradients, water, and natural fractures. So geothermal grew in a few niches.

Superhot geothermal shuffles the deck: Instead of looking for where nature already created a reservoir, engineers drill down to hot rock, then build the reservoir themselves.

From shale playbook to superheated rock

The drilling crew sinks injection and production wells into deeper, hotter rock—often granite. Directional drilling and fracking techniques honed on shale create a network of fractures connecting the wells. Cold water flows down the injection well, soaks up heat, and returns up production wells as high‑enthalpy fluid ready for a power plant.

At Quaise Energy, we’re designing well pairs and triplets targeting 20–40 MW of electric output to compete with gas‑fired units on a per‑pad basis. Going superhot changes the math: at temperatures above roughly 572°F (300°C), a well can deliver up to 10 times more energy than typical geothermal producers at similar flow rates, for decades with no carbon emissions.

The drilling wall

The main obstacle lurks in the wellbore. Conventional drilling can reach depths greater than 6 miles and handle superhot formations, but rarely both at once without runaway costs.

As depth and temperature climb, drill bits encounter hard crystalline rock. Penetration rates slow, and non-productive time explodes as crews withdraw gear to replace worn bits, swap tools, and troubleshoot equipment. Each round trip burns time and money, sending costs exponentially higher.

Scaling superhot geothermal requires flattening that curve, so depth and temperature no longer combine to wreck the budget.

Millimeter-wave drilling: Fusion tech goes downhole

Here at Quaise, we tackle that challenge with millimeter‑wave drilling, which relies on energy‑matter interaction instead of mechanical crushing. It borrows from nuclear fusion, growing out of research started at MIT in 2008.

A surface gyrotron generates high‑power microwave beams in millimeter wavelengths, carried down the well via a metallic waveguide. When the beam hits rock, minerals absorb the microwaves, heating rapidly to crack, melt, or vaporize it into fine particles or ash. A gas stream travels down the waveguide, sweeping the particles to the surface.

Avoiding grinding contact minimizes downhole equipment wear. Relying on energy delivery rather than torque keeps performance stable as depth increases. In principle, millimeter‑wave drilling makes 5‑ to 10‑mile holes routine. Extracted energy repays the investment within months and powers continued drilling. From a safety standpoint, it mirrors a microwave oven heating food—just at far higher power with industrial‑grade safeguards.

A first project on the flanks of a volcano

Quaise’s first full‑scale demonstration, funded by our recent $134 million Series B, will not wait for the deepest wells.

We hold a lease on the side of the Newberry Volcano in central Oregon, where superhot conditions start at 2–3 miles. Roads, a four‑acre well pad, and initial permits are in place.

An initial confirmation well will validate temperature profiles, rock properties, and stress fields, later converting to a monitoring well. Next, we drill an injection–production pair to 575–660°F (300–350°C) using commercially available tools, followed by another production well to form a triplet.

Later phases will go deeper and hotter, adding millimeter‑wave drilling to support 250 MW from six wells on the initial pad and demonstrate competitive power production from superhot EGS.

Safety, workforce, and the road to scale

EGS operations pump water and proppant—not hydrocarbons—through wells engineered thousands of feet below aquifers.

We manage induced seismicity risks with dense sensor networks and conservative injection strategies; events at DOE’s FORGE site and Fervo projects are so small they are nearly undetectable on the surface.

Our sector welcomes the oil and gas skillset wholesale: reservoir and drilling engineers, geologists, rig crews, and technicians can pivot with modest retraining.

Our larger hurdle is getting incumbents to treat geothermal as a core business. With today’s focus on 24/7 firm power and solving permitting and grid queue challenges, superhot geothermal can become the global backbone of a decarbonized grid.

About the Author

Matt Houde is co-founder and chief of staff of Quaise Energy and a board member of Geothermal Rising, the largest direct-membership professional and trade association serving the geothermal industry.

Virtually any industrial-scale process involving combustion must monitor its flue gas emissions for a specified profile of air pollutants. Environmental regulations call for this monitoring to be continuous, such that any time the process is operating, a continuous emissions monitoring system (CEMS) is also operating, recording levels of the specified pollutants. These regulations are set by groups such as the European Commission on Energy, Climate Change, and Environment, and the U.S. Environmental Protection Agency (EPA).  

A CEMS is not part of a larger process control system, but it must instead function entirely independently so it can reliably record data for reporting to the relevant regulators. It may pass information to the automation system because analyzing CEMS data can help evaluate and improve processes upstream from its measurement point, but this can’t interfere with its main purpose. 

The pollutants that a given CEMS must record are determined by the context, reflecting whatever fuels are being used, along with other factors such as the volume of emissions. A CEMS uses various gas analyzer technologies to detect and quantify the required pollutants, as many technologies can only handle one gas. 

For example, a coal-fired boiler has a much different flue gas profile than a natural gas-fired turbine. Typical pollutants in power generating plants, whether for utilities or industrial sites that are monitored by extractive, cold/dry analyzer systems, can include:  

• Nitrogen oxides (NO_x). 
• Sulfur dioxide (SO₂). 
• Carbon monoxide (CO). 
• Carbon dioxide (CO₂). 
• Unburned hydrocarbons. 
• Ammonia (NH₃), usually residue from a NO_x suppression system. 
• Particulates.

While other applications and fuels may result in a longer list of pollutants requiring monitoring, these tend to be more specialized. 

Gathering data to satisfy regulators requires analyzer technologies capable of measuring each pollutant with the required degree of accuracy. Traditionally, this called for a variety of analyzers, each specialized for a given pollutant. This made these systems complicated and costly for operating companies because each analyzer type may have had particular maintenance quirks, requirements for calibration, and list of consumables. Some analyzers struggle where multiple gases interfere with each other, masking true readings. For example, CO₂ and CO can be difficult to separate for some technologies, and water vapor can absorb NO₂ and SO₂, reducing accuracy. 

Some technologies performed readings in situ, meaning they used a probe inserted into the stack. Others had one or more sampling systems to draw flue gas out of the stack, prepare it, perform the analysis, and reinject it. This often left operators having to support multiple branches of the CEMS tree (Figure 1) with multiple sensing techniques and sample conditioning systems. 

To complicate matters further, maintaining multiple systems requires skilled individuals for each, stretching personnel resources. If some element of the larger CEMS program fails, fines from the regulator will certainly follow, or worse, a shutdown may be forced.  

Choosing the best fit technology for measuring multiple analytes

The ultimate desire for plant operators is a single analyzer technology capable of measuring every pollutant with one unit. Unfortunately, there is no single analyzer technology yet capable of measuring all common analytes simultaneously. But fortunately, that limitation does not preclude using more than one technology in a single unit, such that they can share a single extraction mechanism. This alone is a major advance to reduce the need for a larger population of single-purpose analyzers, and this modular approach to configuring analyzers enables the best fit technology to be selected for each gas requiring monitoring. 

One of the most versatile analyzer technologies available today is laser absorption spectroscopy, where an infrared laser sends its light through the gas sample to a detector able to measure intensity at specific wavelengths (Figure 2). Selected wavelengths are tied to absorption characteristics of the desired analytes, so measuring the level of signal attenuation due to absorption allows for calculation of the concentration of target gas present.  

Rosemount QX1000 Continuous Gas Analyzer (Figure 3) can include up to three of these laser modules in a self-contained measurement bench containing all the necessary electronics, detectors, and sample cells to measure gases such as NO, NO₂, CO, CO₂, and SO₂. Depending on the configuration, the laser bench can measure one to four gases, and it can be supplemented by an additional paramagnetic measurement bench to measure O₂.  

Benefits of simplicity 

One of the major advantages of laser absorption spectroscopy is its simplicity. There are no moving parts and few consumables, and the laser and detector are both exceptionally stable, allowing extended operation between calibrations. Newer analyzer designs have significantly increased ease of installation into existing infrastructure, making it virtually plug-and-play.  

The modular design of the analyzer facilitates in-field service and its low maintenance design reduces operating costs, but more importantly, it ensures a high degree of availability, preventing CEMS outages when operation is critical and there is potential for fines. In applications where O₂ measurement is also required, it can be provided by an additional paramagnetic measurement bench. 

The supporting sample extraction system for laser absorption spectroscopy is usually the dry method where the gas stream is chilled and dehydrated to eliminate most water vapor, reducing acidity (Figure 4). This method is used widely, so many facilities may already have it installed to service previous analyzer types. 

Recent analyzer designs have improved the operator interface, adding web server capabilities so a given unit can be accessed from multiple areas within a facility, or even remotely (Figure 5). This simplifies data collection, analysis, and report generation for regulatory organizations.   

This analyzer approach makes it possible for a location to configure a unit tailored for the specific application and monitoring requirements. The range of pollutants covered by this unit will not always be sufficient to cover specific analytes where less common fuels are in use, but additional analyzers can be easily added to handle these rare applications. However, this approach has a high potential to reduce the number of analyzers required since the range it covers encompasses many of the most common possibilities. Let’s look at two very different examples.  

Case study 1: European gas turbine test facility 

A European electric utility company operates an R&D facility where it develops methods to draw higher efficiency out of its fleet of gas turbine installations. The test facility maintains a gas turbine (Figure 6) so engineers can evaluate potential improvements suitable for implementation across multiple plants. Naturally, when the test turbine is operating, it is subject to the same regulatory requirements as any other operating unit, therefore it maintains its own CEMS.   

The turbine and its generator are also connected to the local grid so it can be called upon when necessary to contribute to the utility’s combined output. Consequently, there will be periods when it must operate continuously, possibly for weeks at a time, so it is also subject to the same critical availability demands as others in the fleet. 

The CEMS was originally designed around a group of individual analyzers. They worked well enough for intermittent operation during testing, but they were not suitable for sustained operation when the turbine was added to the grid. Emerson’s engineers worked with the utility to determine the required list of pollutants and their ranges, and they then configured a Rosemount QX1000 Continuous Gas Analyzer to monitor four pollutants.  

Laser absorption spectroscopy measures CO, NO, and NO₂; and a paramagnetic sensor measures O₂, within these ranges: 

• CO, 0-60 to 0-400 ppm with lowest limit of detection (LOD) 0.4 ppm. 
• NO, 0-180 to 0-1200 ppm, LOD 1.2 ppm. 
• NO₂, 0-75 to 0-500 ppm, LOD 0.5 ppm. 
• O₂, 0-5 to 0-25%, LOD 0.5% full scale. 

All of these are included in the single analyzer, with one sampling system. 

Case study 2: Energy from waste incinerator 

Some of the most complex CEMS installations are at energy from waste (EfW, also known as municipal solid waste) incinerators (Figure 6) due to the unpredictable range of products that may be burned, with mixes of plastic, paper, wood, and other waste materials. The flue gas stream can include heavy metals, dioxins/furans, and acid gases—along with more conventional pollutants discussed here—in widely varying amounts. These streams are notoriously difficult to separate into individual streams for analysis, so some are considered collectively, with one or two serving as proxies for others.

One such facility in the UK approached Emerson with a challenge to replace its aging CO analyzer. Emerson’s engineers proposed a Rosemount QX1000 in its most basic configuration, with a single laser absorption spectroscopy module to measure CO and a paramagnetic sensor for O₂. Since the normal amount of CO in the stream was relatively high, the unit was ranged to handle the likely amount: 

• CO, 0-300 to 0-2000, LOD 2 ppm. 
• O₂, 0-5 to 0-25%, LOD 0.5% full scale. 

Driving the technology decision 

Utility and industrial power generators want a CEMS with the simplest, most cost effective, and reliable approach to solve their measurement challenge. Historically, many analyzers have been complex, requiring significant maintenance attention and consumables. Fortunately, technologies have advanced, becoming simpler and easier to operate than their predecessors. A prime example is Rosemount™ CX1000 Continuous Gas Analyzer, which provides performance and stability for operators, while improving availability and reducing cost. 

To regulatory bodies around the world, continuous operation of a CEMS is paramount. If fuel is burning, the CEMS must be working or the facility will be liable for fines, shutdowns, and possibly exposure to litigation and other penalties. Worse, if production must stop due to an unscheduled analyzer outage, revenue will be lost. To address the mandated availability and data quality, newer designs now provide the ability to combine multiple measurement technologies in a single unit, a world’s first.

About the author

Dr. Beth Livingstone is the global product manager for the quantum cascade laser process gas product line at Emerson. Beth holds a Master’s Degree in Chemistry and a PhD in Physical and Theoretical Chemistry, both from the University of Oxford. 

The number of shares to be offered and the price range for the proposed offering have not yet been determined, and the proposed offering will be subject to market and other conditions, Westinghouse said.

The announcement comes as growing electricity demand projections tied to artificial intelligence, data centers, electrification and domestic manufacturing expansion have renewed interest in dispatchable generation resources, including nuclear power.

Since a $7.9 billion deal in 2022, Westinghouse Electric’s ownership is split between Brookfield Renewable Partners (51%) and Cameco (49%). Westinghouse Electric emerged from Chapter 11 bankruptcy in 2018, following a nearly 17-month bankruptcy reorganization stemming from financial and construction challenges with its nuclear power plant projects.

Last month, the U.S. Department of Energy (DOE), through its Office of Energy Dominance Financing (EDF), issued a conditional loan commitment of up to $17.5 billion aimed at accelerating the deployment of 10 new large-scale Westinghouse AP1000 reactors across the United States. Under the proposal, the financing would be distributed through up to five separate loans, with each loan supporting a two-reactor project site. Westinghouse would partner with as many as five utilities or energy companies to develop the projects.

The AP1000 is the only licensed large-scale advanced commercial reactor operating in the nation. Each unit can generate approximately 1.1 GW of electricity, meaning the proposed 10 reactors would provide roughly 11 GW of new capacity.

The last two large nuclear reactors completed in the United States, Vogtle Units 3 and 4 in Georgia, entered commercial operation in 2023 and 2024, respectively. The AP1000 units were the first newly built commercial nuclear reactors to come online in the U.S. in more than 30 years.

Building a nuclear power plant is one of the most complex and capital-intensive infrastructure undertakings in the energy sector. Large nuclear projects often face lengthy development timelines, supply chain challenges, inflationary pressures and construction risks. Vogtle Units 3 and 4 ultimately cost billions of dollars more and took years longer to complete than originally projected.

However, industry leaders and policymakers frequently point to Vogtle as a learning opportunity for future deployments. They argue that lessons learned during the design, licensing, construction and commissioning processes could help reduce costs and shorten schedules for subsequent AP1000 projects.

Last fall, Westinghouse Electric Company, Cameco Corporation and Brookfield Asset Management announced that the United States federal government entered into a strategic partnership meant to accelerate the deployment of nuclear power. The parties argue the partnership is in accordance with the President’s May 23, 2025 Executive Orders, which were meant to quadruple domestic production of nuclear power within the next 25 years. At the center of the new strategic partnership, at least $80 billion of new reactors are targeted to be constructed across the United States using Westinghouse nuclear reactor technology.

The statement contradicts repeated assertions by Energy Secretary Chris Wright and other officials that the projects were canceled because they did not adequately advance the nation’s energy needs or had other problems that made them a poor investment of taxpayer dollars.

Democrats and environmental groups seized on the court filing Friday, saying the administration had “weaponized” the federal government to kill good jobs and punish working families because of their political views.

Democrats say what was ‘obvious’ has now been acknowledged

“This administration has now admitted in court what has long been obvious: it terminated nearly 300 cost-cutting energy projects for no reason other than the fact that the states they were in did not vote for the president in the 2024 election,” said Rep. Marcy Kaptur of Ohio and Sen. Patty Murray of Washington state. Both are high-ranking Democrats on the House and Senate Appropriations committees, respectively.

“Weaponizing the federal government like this is outright un-American, and it’s hardworking families already struggling with sky-high costs who are suffering the consequences of this corrupt abuse of power,” Kaptur and Murray said.

They called on congressional Republicans to join them in holding the Trump administration “accountable for the President’s failure to look out for all Americans.”

The Energy Department announced last October that 321 funding awards across 223 projects were terminated, saying that after review, they “did not adequately advance the nation’s energy needs or were not economically viable.”

The cuts, part of broader attacks from President Donald Trump on climate programs and clean energy funding, slashed federal support for projects to build battery plants, develop hydrogen technology, upgrade the electric grid and capture carbon dioxide emissions.

Russell Vought, the White House budget director, highlighted the cutbacks in a social media post, saying money “to fuel the Left’s climate agenda is being cancelled.”

The Energy Department did not immediately respond to a request for comment.

Projects from many states were cut

Projects that were cut were located in California, Colorado, Connecticut, Delaware, Hawaii, Illinois, Maryland, Massachusetts, Minnesota, New Hampshire, New Jersey, New Mexico, New York, Oregon, Vermont and Washington state. All 16 targeted states supported Harris, but Wright said the cuts were “business decisions” based on whether the projects were a good use of taxpayer money or not.

The cuts were immediately challenged in court, and more than two dozen Democratic members of Congress, led by California Sens. Adam Schiff and Alex Padilla and Rep. Zoe Lofgren, wrote a letter to the Energy Department’s acting inspector general requesting a formal investigation. The department’s internal watchdog launched an investigation in December.

Government lawyers had p reviously confirmed in a court filing late last year that the selection of grants in fact “was influenced by whether a grantee’s address was located in a State that tends to elect … Democratic candidates in state and national elections (so-called “Blue States”).”

That filing came in a separate suit filed by clean energy groups and the city of St. Paul, Minnesota, over the canceled funding. The most recent admission came in a case called Thakur v. Trump that’s been ongoing since last spring. Federal lawyers acknowledged that they used keywords related to diversity, gender, vaccine hesitancy and COVID-19 to screen for projects that ran afoul of the Trump administration’s priorities.

Holly Bender, chief program officer for the Sierra Club, said the latest court filing shows “the Trump administration is brazenly admitting to a vindictive approach to cancelling much-needed energy infrastructure that ignores the job losses, air pollution and increasing bills that people are experiencing everywhere.”

Instead of “building the energy projects we desperately need,” billions of American taxpayer dollars are “going to line the pockets of a small handful of fossil fuel company CEOs,” Bender said, citing nearly $3 billion pledged by the Trump administration to cancel offshore wind projects in favor of fossil fuel projects such as natural gas and coal.

Di-Hydro is an EU-funded research project that addresses the need to modernize and digitalize the hydropower sector. The average age of hydropower plants varies depending on the continent; for Europe, it is 42-46 years, about 64 for the US, and an estimated 20 years in China. The hydropower sector will require modernization to keep up with current and future demand.

To fully harness this potential and bolster renewable energy production for a climate-neutral economy, Di-Hydro aims to digitize hydropower plants (HPPs) by developing smart devices and data acquisition techniques to predict and control operations and maintenance. Furthermore, digital twins (DTs) have been developed to facilitate data exchange, alongside an intelligent decision-making tool for optimal coordination of power generation considering societal, weather, water flow, environmental, and biodiversity data.

Di-Hydro’s Sensors

Within the spectrum of digitalization of HPP operations, the Di-Hydro project has developed sensors for two different applications. The first set of sensors is destined for structural health monitoring (SHM) of machinery or infrastructure, while the second is for monitoring environmental and biodiversity parameters.

The purpose of the SHM sensor node that has been developed by CERTH is to provide a low-cost, low-power solution that can be retrofitted easily without considerable invasiveness, capable of providing real-time and continuous monitoring of defects and damages that may occur on rotating machinery or infrastructure at a hydropower plant. The SHM sensor consists of an acoustic emission (AE) sensor system paired with a multisensor unit that carries a triaxial accelerometer unit, gyroscope, magnetometer, barometer, and temperature and humidity sensor.

The AE system is based on the Qawrums RAEM-2 system architecture and is used for detecting elastic transient waves that are generated from a material under load when cracking, deformation, or other permanent changes occur. Other sources that generate AE signals related to flaws are defective gears and faulty bearings from rotating parts and industrial drive train assemblies. The AE data are automatically uploaded to an online cloud server, which also plots and displays the evolution history of amplitude, RMS, power, and ASL values (Figure 2). The multisensory unit is based on the Sense HAT (B) board and is connected to a Rasbery Pi microcomputer.

This sensor node has been installed at the Ilarionas HPP in Greece to detect potential failures in the plant’s drainage pumps and penstock. These two locations did not previously have this kind of sensor and were indicated as areas of interest that required monitoring.

The other main application area of deployed sensors in the DI-HYDRO project includes water quality and biodiversity monitoring sensors. HPPs can significantly affect water quality and environmental conditions in water reservoirs and river basins.

Solving The Core Problem

The key issue is water stagnation, which can lead to stratification, layers of water with different temperatures and oxygen levels. This reduces oxygen mixing and creates conditions for microbiological and chemical imbalances, which limits oxygen mixing and creates conditions for microbiological and chemical imbalances. For example, nitrification processes may intensify in low-oxygen zones, altering nutrient cycles and potentially leading to the accumulation of harmful nitrogen compounds.

Another common problem is the formation of algal blooms, often called “green soup”. These occur when excess nutrients, such as nitrogen and phosphorus, and warm, stagnant conditions promote rapid algal growth. Some of these blooms can produce toxins, reduce oxygen levels during decomposition, and harm aquatic life and human health. They can also cause clogging in HPP piping systems, reducing or even completely halting power generation.

Monitoring these issues is critical for both HPP operations and broader societal needs, as reservoirs frequently serve as sources of drinking water, irrigation, and recreation. Poor water quality can increase treatment costs, damage ecosystems, and pose health risks.

A new electrochemical sensor for ammonia detection, fluorescence-based algae sensors, and an E.coli biosensor were delivered by INOSENS and integrated into a sensor system for measuring temperature, turbidity, pH, conductivity, and dissolved oxygen (Figure 4) to improve understanding of water parameters and conditions. By collecting real-time data in combination with manual measurement of total coliform and E. coli, these sensors enable early detection of problems, support decision-making (e.g., controlled water releases or aeration), and help mitigate impacts before they become severe.

Furthermore, AIMEN has deployed a portable multiparametric platform that allows remote water sampling at any point in the reservoir. This multiparametric platform is a portable, rough suitcase equipped with a tryptophan-like fluorescence sensor that can estimate the pathogenic contamination of water samples within a few seconds, using E. coli natural fluorescence as the main indicator. The suitcase is also equipped with a portable version of a Digital Holographic Microscope (DHM) that, through laser interferometry combined with microscopy objectives and a digital camera, can produce holograms of water samples. Image processing is applied to obtain 3D images of present microorganisms, allowing the assessment and estimation of the population of key microorganism species like cyanobacteria, green algae, etc. This helps to monitor the evolution of the reservoir microscopic biodiversity.

A decision-making system model that has been developed integrates data from multiple sources, including historical water quality reports, sensor data from measurements, and HPP operational parameters obtained from the SCADA system (Figure 5). These datasets, with significantly different temporal resolutions, ranging from a few measurements per year to minute-level sensor observations, were combined to develop two interconnected AI/ML models. The first model assesses and predicts biological activity in the reservoir using sensor data and automated analysis of DHM images. The second model integrates the outputs of the first model with hydropower plant operational and historical data to correlate environmental and biodiversity changes with hydropower plant performance, improve predictive maintenance, environmental compliance, and operational efficiency.

The Di-Hydro project has received funding from the European Union’s Horizon Europe Research and Innovation Programme under grant agreement N° 101122311.

Originally published in Factor This.

About the Authors

Alkiviadis Tromaras, PhD, is a Research Associate and head of the lab for air transport systems and services at the Centre for Research and Technology, Hellas (CERTH). He has a PhD in Manufacturing Engineering. He is currently the coordinator of the Di-Hydro project and is actively engaged in non-destructive testing of transport or energy infrastructure and means.

Vasa Radonic, PhD, is a Principal Research Fellow and Assistant Director of Science at the Biosense Institute. He received a PhD in electronics in 2010 from the University of Novi Sad. He has authored and co-authored two book chapters, 30 journal papers, more than 60 conference papers, and 10 technical solutions. He was a steering committee member and the vice president of the Scientific Council at the BioSense Institute from 2015-2020.

Miguel Placer Lorenzo is a Senior R&D Researcher at the AIMEN Technology Centre. He has 10 years of experience in photonic technologies, covering the design, simulation, development, and validation of photonic and biophotonic sensors for environmental monitoring, water treatment digitalization, and bioprocess control. Miguel has been involved in EU projects on digital water, bioprocess monitoring, circular economy, and energy, developing photonic sensors combined with AI for process optimization, risk prevention, environmental safety, and predictive maintenance.

Nikolaos Aggelopoulos is a Research Associate at the Hellenic Institute of Transport (HIT) of the Centre for Research and Technology Hellas (CERTH). His doctoral research thesis is focused on damage detection and damage evolution monitoring in Fibre-Reinforced Materials using the Acoustic Emission technique. He is a member of the Technical Chamber of Greece and has worked as a Project Engineer in the industrial sector. His research interests include Structural Integrity Monitoring, Failure Detection, Signal Processing, Metallurgy, and Fiber-Reinforced Composite Materials.

FIA data shows that the sector has reported a total of $14.24bn since the annual survey began in 2021 and that it now employs more than 16,000 people.

For its sixth report, the FIA surveyed 56 fusion companies – up from 23 in 2021 – with six new entrants since 2025 and three companies withdrawing. 

Major funding rounds making up the 2026 figures include: Commonwealth Fusion Systems (CFS), which raised an $863m Series B2 round in August 2025; Inertia Enterprises, which raised a $450m Series A in February 2026; Helion Energy, which raised $465m in June 2026; and Proxima Fusion, which raised $518m in July 2026. 

For the first time, the report included incoming investment from companies preparing to enter the public markets. General Fusion and TAE Technologies are preparing to join the Nasdaq exchange in 2026 and both received hundreds of millions of dollars in new investment as part of the process of going public. According to the FIA, public market participation is expected to broaden investor confidence while exposing the sector to greater commercial scrutiny.

Planning apace

Beyond investment figures, the report suggests that fusion developers are increasingly planning for commercial deployment. In terms of siting and power purchase agreements (PPAs), the data reveals that six companies already have a siting agreement, with another four actively evaluating options. Five companies have a PPA, offtake agreement or similar commercial commitment, with two more in discussions. 

Perhaps unsurprisingly, these agreements are being hastened by the growing demand for energy from AI infrastructure. High-profile partnerships, including Microsoft’s agreement with Helion Energy and Google’s collaboration with Commonwealth Fusion Systems, are helping establish future demand for fusion-generated electricity before commercial plants begin operating.

There’s no one-size-fits-all approach to fusion technology and this year’s report confirms that almost half of surveyed companies (48%) continue to pursue magnetic confinement technologies, while 21% are focused on inertial confinement and 14% on magneto-inertial approaches. Several alternative concepts are also under development.

As well as technical diversity there is considerable geographic diversity at play. The USA remains the center of private fusion investment – with 28 companies included in this year’s survey and all five billion-dollar-funded businesses based there. Companies from 12 other countries now feature in the report, including four each from the UK, Germany and China, alongside growing activity in India, France and Japan.

Despite such diversity, the FIA emphasises that what hasn’t changed is the timeline. It reports that 71% of fusion companies still expect the first fusion plant to deliver commercial electricity by the 2030s.

Energy security

Discussing the current state of play, Andrew Holland, the FIA’s chief executive, said: “This year’s report shows how far fusion has come – from being defined by national labs and government R&D programs to being dominated by private fusion investment totaling over $4bn in just one year.”

Holland added: “This year’s record funding comes at a time when the imperative for fusion energy is greater than ever as energy security demands and environmental threats are joined by the need for huge amounts of clean energy to fuel the AI revolution.”

The imperative may be great but the FIA acknowledges that several challenges remain. 67% of respondents still cite funding as the biggest short-term challenge. Other challenges named were power efficiency (64%) and neutron-resilient materials (64%). For the longer term, the availability of neutron-resilient materials (57%) was the leading concern, followed by power efficiency (52%) and tritium self-sufficiency (52%).

Despite these hurdles, Holland remains optimistic. “I’m confident that the sector has the ability to deliver commercial fusion in the 2030s,” he declared. “The existence of siting agreements and power purchase agreements shows that commercial fusion energy is on the horizon. However, alongside private investment, fusion companies still need the support of governments to address common challenges including the availability of resilient materials and the fusion fuel cycle. The governments that update their programs and funding priorities to meet the sector’s needs today will be the ones to capitalize on this vital emerging industry.”

Gauss success

One company that was set up precisely to capitalize on this emerging industry is German organization Gauss Fusion. And it has just announced two developments on its path to commercializing fusion: Dr Uwe Bau has appointed as CEO; and the company has released its evolved strategy and fusion energy industrialization roadmap

In other personnel developments, Bau and the chief corporate development officer, Abraham Taherivand, have also been appointed as managing directors. Gauss founder, Dr Frank Laukien, has returned to his role as executive chair of the board, where he is joined by vice chair, Dr Michael Peiniger.

Bau, who succeeds Milena Roveda as chief executive, holds an engineering doctorate from RWTH Aachen, Germany and he researched advanced energy systems at Forschungszentrum Jülich before joining McKinsey & Company in energy business consulting. He joins Gauss from RI Research Instruments, where he was business section head for Semicon OEM Technologies.

The leadership changes come as Gauss moves into the next phase of its development program, following the completion of the conceptual design report (CDR) for its GIGA fusion power platform. The report establishes the overall system architecture for the proposed power plant, defining key engineering interfaces and identifying the technologies that will require further development, testing and validation before commercial fusion plants become a reality.

With the conceptual design now complete, the company is focusing on advancing several proprietary technologies that underpin its fusion power strategy. These include a high-field stellarator design, Demountable Mitchell Magnets (DMM), the HEXA tritium breeding and fuel cycle, a high-frequency electron cyclotron resonance heating (ECRH) system, and a new divertor concept. 

Together, Gauss intends these technologies to address many of the practical engineering challenges associated with building, operating and maintaining fusion power plants, while supporting the company’s long-term goal of delivering a first-of-a-kind commercial-scale facility.

Originally published in Factor This Power Engineering sister publication Enlit World.

For decades, power generation equipment was designed around a relatively straightforward objective. Whether developing turbines, heat exchangers, pumps or associated systems, engineers sought to maximize efficiency under predictable operating conditions. Large thermal power stations operated continuously, demand profiles were relatively stable, and equipment spent much of their working lives close to their optimum design point. 

That model is changing rapidly. Renewable generation, energy storage, electrification and the rapid growth of AI infrastructure are creating electricity systems that are far more dynamic than those they replace. Conventional generation is increasingly required to respond to fluctuating renewable output rather than provide continuous baseload power, while entirely new technologies are being integrated into infrastructure that was never designed to accommodate them. The result is a fundamental shift in engineering priorities. 

The challenge is no longer simply achieving maximum efficiency. Modern power systems must continue operating reliably despite frequent cycling, changing thermal loads and increasingly complex interactions between multiple technologies. Designing for flexibility has become just as important as designing for performance, requiring engineers to rethink long-established assumptions about materials, thermal management, system integration and long-term reliability. 

The technologies driving the energy transition continue to evolve, but the more significant transformation is taking place within engineering itself. Future success will depend not on optimizing individual components in isolation, but on understanding how entire systems behave under conditions of continual change.

Engineering for systems that rarely stand still

The move away from steady-state operation is changing the way power generation assets are designed, operated and maintained. Equipment that once ran continuously for weeks or months is now expected to respond to far more variable operating conditions as renewable generation grows and electricity demand becomes less predictable. Combined-cycle gas turbines provide a clear example. Rather than operating primarily as baseload generation, they are increasingly required to start more frequently, ramp output rapidly and perform efficiently across a much wider operating range than their designers originally envisaged. 

While that flexibility is essential for maintaining grid stability, it introduces engineering challenges that differ fundamentally from those associated with continuous operation. Every start-up and shutdown cycle creates thermal expansion and contraction throughout the system, while changing temperatures and pressures place repeated mechanical stresses on critical components. Over time, those conditions accelerate fatigue, increase the risk of creep, oxidation and corrosion, and place greater demands on maintenance strategies and long-term asset management. Equipment is no longer being asked simply to operate efficiently; it must do so repeatedly under conditions of continual change. 

The consequences extend well beyond individual components. Improving the performance of one part of a system can have unintended consequences elsewhere. Raising operating temperatures may improve efficiency but require different materials. Altering flow conditions may influence pressure losses or increase the likelihood of fouling and corrosion downstream. Optimizing one component in isolation is becoming progressively more difficult because overall system performance depends on how effectively every element works together. 

That reality is placing greater emphasis on system integration from the earliest stages of development. Many emerging low-carbon technologies are still progressing through relatively low technology readiness levels, meaning engineers are often designing and building concurrently while managing considerable technical uncertainty. Close collaboration between equipment suppliers, system integrators and end users is therefore becoming essential, supported by increasingly sophisticated modelling techniques that help predict how design decisions in one discipline influence performance across the wider plant. 

The engineering challenge has shifted from designing individual assets around a single operating condition to developing systems capable of maintaining reliable performance across a much broader operating envelope. As renewable penetration continues to increase, balancing flexibility with reliability will become one of the defining characteristics of successful power infrastructure.

Thermal management becomes a strategic engineering discipline

If flexibility is changing how power systems operate, it is also changing the way engineers think about heat. Thermal management has always been central to power generation, but it is now becoming one of the factors that determines whether new technologies can be deployed successfully. As developers pursue higher efficiencies, smaller plant footprints and more responsive operating characteristics, systems are being pushed towards increasingly demanding temperatures, pressures and power densities. The challenge is no longer simply transferring heat efficiently but doing so reliably under operating conditions that are continually changing.  

Higher operating temperatures improve thermodynamic efficiency, but they also expose the limitations of conventional engineering solutions. Components experience greater thermal gradients, accelerated creep, oxidation and corrosion, while higher pressures increase demands on structural integrity, sealing technologies and pressure containment. These effects are rarely confined to individual items of equipment.  

Material selection, equipment sizing, safety margins and maintenance strategies all become closely linked, meaning relatively small design decisions can influence the performance of the wider system. 

Engineering therefore requires a careful balance between theoretical performance and commercial reality. Maximum efficiency may demand specialized materials, larger heat transfer surfaces or more complex system architectures, but incremental gains can quickly become disproportionately expensive. Successful projects depend less on pursuing absolute efficiency than on identifying the point where performance, reliability and commercial viability remain in balance. In many applications, accepting a modest reduction in thermal performance produces a system that is more robust, easier to manufacture and ultimately delivers greater value throughout its operating life. 

Supercritical carbon dioxide power cycles illustrate these trade-offs particularly well. Their ability to achieve high efficiencies within relatively compact plant layouts has attracted considerable attention, but operating at elevated temperatures and pressures introduces significant engineering challenges. Material availability, pressure containment, allowable pressure losses and equipment size all become closely linked, while decisions affecting one design parameter quickly influence several others. Addressing those interactions demands a systems engineering approach rather than optimization of individual components in isolation. 

One technology helping engineers overcome many of these challenges is the Printed Circuit Heat Exchanger (PCHE). Manufactured by chemically etching fine flow channels into metal plates before diffusion bonding them into a single compact core, PCHEs offer exceptionally high heat transfer efficiency within a small footprint while operating safely at the high temperatures and pressures demanded by applications such as supercritical CO₂ power cycles, advanced nuclear systems and thermal energy storage. Their combination of compactness, strength and thermal performance enables engineers to reduce plant footprint, improve efficiency and integrate increasingly demanding energy systems without compromising reliability. 

This is one reason advanced heat transfer technologies are assuming greater strategic importance across the energy sector. Whether supporting supercritical CO₂ cycles, recovering industrial waste heat or enabling long-duration thermal storage, their contribution extends well beyond improving efficiency. They enable technologies that would otherwise struggle to operate under increasingly demanding conditions while allowing engineers to integrate multiple energy sources within a single system architecture. As power generation becomes more flexible and interconnected, thermal management is evolving from a supporting discipline into one of the principal enablers of next-generation energy infrastructure. 

Engineering in practice

The technologies needed to decarbonize power systems are, for the most part, already available. Renewable generation continues to expand, energy storage technologies are maturing and advanced concepts such as Small Modular Reactors, thermal storage and supercritical CO₂ power cycles continue to progress towards wider deployment. The greater challenge is no longer developing individual technologies, but integrating them into reliable, commercially viable systems capable of responding to increasingly dynamic operating conditions. 

That challenge is becoming more acute as electricity demand accelerates. The rapid expansion of AI infrastructure and hyperscale data centers is creating a new generation of energy users requiring large quantities of reliable power, often within demanding timescales. In many regions, demand is growing faster than new generation and transmission infrastructure can be delivered, placing greater emphasis on flexible generation, energy storage and more intelligent use of existing assets. Engineering priorities now extend well beyond the power plant itself to encompass transmission networks, grid connections, control systems and the supply chains needed to support them. 

Meeting those challenges demands a far more collaborative approach to engineering than has traditionally been the case. Mechanical, electrical, control and software disciplines can no longer operate independently before handing responsibility to system integrators. Decisions affecting temperatures, pressures, operating profiles, maintenance strategies and control systems all influence one another, requiring multidisciplinary collaboration from the earliest stages of development. As technologies continue to mature, that collaboration increasingly extends to manufacturers, construction specialists and supply chain partners whose expertise is essential if projects are to move successfully from concept to commercial deployment. 

The district heating project developed by DIN Forsyning in Esbjerg, Denmark, demonstrates what this systems-based approach looks like in practice. Replacing a coal-fired combined heat and power plant with what is believed to be the world’s largest seawater heat pump using supercritical carbon dioxide as the refrigerant, the project illustrates how established technologies can be combined to deliver capabilities that extend well beyond their individual functions. 

Powered by offshore wind, the installation extracts thermal energy from seawater and transfers it into the district heating network, supplying around 280,000 MWh of heat each year to approximately 25,000 households while avoiding an estimated 120,000 tons of carbon dioxide emissions annually. Its significance, however, lies not simply in replacing fossil fuel generation but in the way it interacts with the wider electricity system. Rather than acting as a passive consumer of electricity, the heat pump adjusts its electrical demand in response to changing grid conditions, providing ancillary services that help maintain network stability as renewable generation fluctuates. 

The project demonstrates how engineering priorities are changing. Traditionally, electricity generation, heating and grid operation would have been designed and optimized largely as separate systems. At Esbjerg they function as parts of a single integrated energy system, where renewable electricity, thermal storage and flexible demand work together to improve overall performance. Heat becomes a valuable means of storing energy, while demand-side flexibility contributes to grid stability rather than placing additional pressure on the network. 

Equally significant are the engineering decisions that underpin the installation. The selection of supercritical carbon dioxide as the working fluid, the integration of high-performance heat exchangers and compressors, the design of the thermal management system and the development of sophisticated control strategies all contribute to the overall performance of the plant. None represents a breakthrough technology in isolation. Their value lies in the way they have been integrated to create a resilient, commercially viable system capable of delivering multiple benefits simultaneously.

Projects such as Esbjerg provide a practical illustration of where the industry is heading. Future energy infrastructure is unlikely to depend on a single transformative technology. Instead, success will increasingly be determined by the ability to integrate proven technologies into flexible, resilient systems capable of responding intelligently to changing operating conditions while supporting wider decarbonization objectives. 

Engineering the next generation of power systems 

The energy transition is often discussed in terms of new generation technologies and the pace at which they can be deployed. Those developments remain important, but the more profound transformation is taking place within engineering itself. 

Designing equipment that performs efficiently under ideal operating conditions is no longer enough. Engineers are increasingly expected to create systems capable of accommodating continual change without compromising reliability, safety or commercial viability. That demands a broader understanding of how materials, thermal management, digital controls and system integration influence one another throughout the operating life of an asset. 

Ultimately, the success of the energy transition will depend on far more than the technologies used to generate electricity. It will depend on the engineering decisions that allow increasingly diverse systems to operate together safely, efficiently and reliably. As power systems become more flexible and interconnected, the ability to integrate technologies into resilient, adaptable infrastructure will become one of the defining engineering achievements of the decades ahead.

About the author

Marie-Louise Rees is a Business Development Engineer at Parker Hannifin with experience in engineering, commercial strategy and key account management. She works closely with customers to identify technically and commercially effective solutions for complex commercial applications

Organizations such as the Electric Power Research Institute (EPRI) and the International Association for the Properties of Water and Steam (IAPWS) have provided numerous technical guidelines for HRSG chemistry control.  I summarized some of the most important details in a previous series for Factor This Power Engineering, which focused on the critical issue of protecting units from flow-accelerated corrosion (FAC)¹.  A key to chemistry control is comprehensive on-line monitoring, and this article summarizes important measurements and their purpose.  Additional and more detailed information is available in References 2-9.  The numerical data in this discussion comes from Reference 2, with notes that describe some supplementary analyses that are very valuable. 

The principles outlined below also apply in many cases to co-generation facilities that have medium- to high-pressure boilers for power production and process heating applications.   

A Brief Review of HRSG Design 

High-purity makeup water requirements and water/steam chemistry control and monitoring for HRSGs are similar to those for older, conventional steam generators.  However, when compared to coal-fired units HRSGs have some major design and operational differences, the most important of which include: 

• The various boiler (evaporator) and superheat/reheat panels (harps) in HRSGs are aligned in parallel along the flue gas path.  This arrangement is different than the waterwall tubes in a coal unit, which can be thought of as a box that comprises the combustion chamber. 

• Essentially no ash fouling potential exists in HRSGs unless the combustion turbine is fired with oil, which is not common.  However, over time particulates that leak through inlet air filters can deposit on outer HRSG tube surfaces, especially if the tubes have fins for enhanced heat transfer. 

• HRSGs are usually of multi-pressure design with the most popular having three, drum-style evaporator circuits. 

Per the last bullet, numerous HRSG designs are available, but Figure 1 outlines the schematic for the most common, the “triple-pressure, feed forward low-pressure (FFLP)” type.  A key aspect is that the low-pressure (LP) circuit is primarily part of the feedwater heating process for the intermediate-pressure (IP) and high-pressure (HP) circuits.  The following discussion is based on this configuration.   

The next sections outline recommended monitoring parameters, and why online analyses are critical to reliable and safe operation.  

Sampling Points and Monitoring Parameters 

The samples of primary importance throughout the steam-generating network are:   

1. Makeup treatment system effluent 
2. Condensate pump discharge 
3. Feedwater or economizer inlet 
4. Boiler water 
5. Saturated steam 
6. Main and reheat steam 

Unless noted, the data in the sections below comes from Reference 2, Table 4, “Guidance Document for Phosphate Treatment (PT) and Caustic Treatment.  Applicable to multi-pressure combined cycle/HRSG units, no copper alloys, with LP drum feeding the IP and HP circuits, no reducing agent added to the cycle [AVT(O) chemistry], and not cooled by seawater or brackish water.”   

I have included the recommended normal limit, or range, of each parameter from Table 4.  However, this is only for general purposes and should not be used as a design guideline.  All projects must be evaluated on an individual basis in consultation with steam generation chemistry experts. 

The circuit pressures from which the data in Table 4 come are: 

• LP Evaporator: 70 psi 
• IP Evaporator: 350 psi 
• HP Evaporator: 2,000 psi 

We will see examples later of how pressure influences chemistry guidelines. 

Makeup Treatment System

The water/steam network in dedicated power units (usually) approximates a closed loop circuit.  However, a small amount of water/steam continually escapes.  These losses are made up with high-purity water.  A common HRSG makeup configuration is ultra- or microfiltration for particulate removal, reverse osmosis (RO) for bulk demineralization, and downstream mixed-bed ion exchange (MBIX) or electrodeionization (EDI) to “polish” the RO effluent.  

RO units typically have a variety of instruments for monitoring system performance.  These are shown in Figure 3.   

• T = Temperature 
• P = Pressure 
• SC = Specific Conductivity 
• Cl₂ = Chlorine Residual Monitor 

The final effluent from either the MBIX or EDI polisher should be of the following purity: 

• Specific conductivity (S.C.):  ≤ 0.1 µS/cm 
• Conductivity after Cation Exchange (CACE):  ≤ 0.1 µS/cm 
• Silica: ≤ 10 µg/kg (µg/kg is essentially equivalent to parts per billion (ppb)) 

These analyses ensure that high-purity water is being distributed to the steam generator(s).   A rise in any of the values indicates that either the MBIX resin has reached exhaustion or that a problem has occurred in the EDI unit.  Prompt corrective action is necessary.   

Regarding CACE, sodium is an oft-selected alternative.  The recommended normal limit is 2 µg/kg. 

Condensate Pump Discharge (CPD)

For power units, the primary location for contaminant ingress is the water-cooled condenser (except, of course, at plants that have air-cooled condensers), where a tube leak(s) allows cooling water to contaminate the condensate.  Impurities that infiltrate include hardness, chloride, sulfate, and silica, which, when subjected to the harsh environment in the steam generator, can cause serious problems, as will be highlighted shortly.  A condensate polisher can provide a buffer against contaminant ingress, but polishers are rare for drum units and will not be included in this discussion. 

Recommended continuous CPD analyses are: 

• CACE: ≤ 0.3 µS/cm 
• Sodium: ≤ 3 µg/kg 
• Dissolved Oxygen (D.O.): ≤ 10 µg/kg 

Sodium monitoring is very effective for detecting condenser tube leaks.  With a tight condenser, sodium levels in the condensate are normally quite low (< 2 µg/kg).  A rise in sodium provides the earliest indication of a condenser tube leak.   

CACE samples are routed through a cation exchange column to replace all cations, including ammonium, with hydrogen ions.  This creates a dilute acid solution of trace amounts of chloride and sulfate ions.  The acid stream is more conductive than the original specific conductivity, so CACE is more sensitive to impurity fluctuations.  Like sodium, a rise in CACE indicates contaminant in-leakage, although this measurement is influenced by carbon dioxide ingress, e.g., from air in-leakage at the condenser.  A common recommendation now is degasified CACE, which utilizes either a re-boiler or nitrogen sparging compartment to remove CO2 from the sample.   

CACE may be worthless at plants in which an alkalizing amine, e.g., ethanolamine, morpholine, cyclohexylamine, etc., is used in place of ammonia for feedwater pH control.  The fraction of these amines that carries over with steam (which is variable depending on the compound³) will decompose in superheaters and reheaters to form small-chain organic acids that artificially influence CACE and lower condensate pH.  The author once consulted on a project where amine decomposition resulted in CPD CACE values typically well above 1 µS/cm, and which once approached 4 µS/cm.  

Dissolved oxygen analyses are important for monitoring condenser air in-leakage.  A sudden increase in dissolved oxygen may indicate a mechanical failure at or near the condenser, which allows excess air to enter the system.  (I observed this phenomenon directly at times over years of condenser performance monitoring at two power plants.)  But a critical item to remember is that the recommended feedwater chemistry program for nearly every HRSG is all-volatile treatment oxidizing (AVT(O)), which requires a small amount of dissolved oxygen and no reducing agent/oxygen scavenger feed.  Some additional comments regarding this chemistry are provided in the next section, but comprehensive details may be found in many of the references and particularly Reference 4.   

A parameter not usually monitored continuously, but which can be significant is total organic carbon (TOC).  If natural organic compounds somehow sneak through the makeup water system and enter the steam generator network, they can break down to organic acids.  TOC may be problematic at some cogeneration plants.  I once assisted with a project that had two combined cycle units which provided power to a facility being converted from import to export of liquified natural gas (LNG).  Numerous steps are required to purify and prepare LNG, and so the condensate return lines to the HRSGs were equipped with on-line TOC analyzers to detect condensate contamination from any of the treatment processes.  

LP Economizer Inlet/LP Evaporator Feed Pump Discharge/IP and HP Economizers

Per Figure 1, the following measurements are recommended for the feedwater network through the LP evaporator and IP/HP economizers: ^2,5 

• CACE:  ≤ 0.3 µS/cm 
• S.C: Consistent with pH 
• pH: 9.2-9.8 
• D.O. (range): 5 to 10 µg/kg 

The dominant issue regarding chemistry control in the HRSG feedwater system is minimization of flow-accelerated corrosion.  The recommended program for nearly all HRSGs is known as all-volatile treatment oxidizing (AVT(O)), which requires high-purity feedwater (with CACE being the standard measurement parameter) and a small D.O. concentration generated by condenser air in-leakage.  Two items are worthy of note here.  First, EPRI guidelines call for a normal CACE limit of 0.2 µS/cm, which is part of their AVT(O) guidelines.⁴ Second, References 4 and 6 point out that a higher D.O. concentration of 20 to 30 µg/kg may be needed to ensure that sufficient oxygen is present for proper carbon steel passivation.  Oxygen injection locations are shown on Figure 1.  Some excellent real-world applications of AVT(O) chemistry are available in Reference 7. 

In high-purity feedwater, specific conductivity and pH monitoring are interlinked.  Ammonia (or sometimes an amine or ammonia/amine blend) is the pH-conditioning agent.  However, direct pH measurement of high-purity water can be tricky, and algorithms have been developed to accurately calculate pH based on specific conductivity and CACE measurements.  Additionally, specific conductivity (S.C.) in high-purity water is directly correlated to the ammonia concentration, and thus S.C. measurements offer better control of ammonia feed than pH.  

Two additional feedwater analyses not shown in the list above, but which often appear in detailed discussions are: 

• Sodium: ≤ 2 µg/kg 
• Iron: ≤ 2 µg/kg 

This author has much direct experience with these measurements.  Regarding sodium monitoring, at two separate power plants, my colleagues and I relied on sodium over CACE for detection of condenser tube leaks.  Sodium measurements are absolutely needed if CACE can be masked by the decomposition products mentioned earlier. 

Iron monitoring provides a direct measurement of FAC (or hopefully lack thereof) and the effectiveness of the feedwater chemistry program.  Ninety percent or greater of iron corrosion products generated by corrosion are particulate in nature, so basic dissolved iron analyses will only detect a fraction of the metal in the sample.  Several methods exist to monitor total iron, and these include: 

• Continuous particulate monitoring 
• Corrosion product sampling 
• Online nephelometry⁸ 
• Grab sample analysis with special sample conditioning 

Regarding the latter method, improved grab sampling techniques are available, in which, with proper sample treatment, total iron measurements down to 1 µg/kg are possible.  This method can provide near real-time data of corrosion rates, although on a snapshot basis. 

Evaporator (Boiler) Water

Two primary goals of boiler water chemistry monitoring are to protect the evaporators from corrosion and to prevent excessive carryover of impurities to the steam system and turbine(s).  The influence of pressure is clearly noticeable when comparing IP evaporator guidelines with the HP guidelines.  As before, the following parameters come from Table 4, Reference 2. 

IP Evaporator Circuit 

• CACE:  < 80 µS/cm 
• S.C.: < 45 µS/cm 
• pH: 9.0-9.8 
• Phosphate: 0.3-7.0 mg/kg 

HP Evaporator Circuit 

• CACE:  < 20 µS/cm 
• S.C.: < 15 µS/cm 
• pH: 9.0-9.4 
• Phosphate: 0.3-2.0 mg/kg 

As has been noted, CACE is a surrogate measurement for chloride and sulfate.  Without proper control, and via mechanisms induced by high heat flux at the tube walls, these anions will concentrate underneath iron oxide boiler tube deposits to cause corrosion.  The reader will note the much lower CACE limit for the HP evaporator due to the higher pressure and heat fluxes.  

Even with effective and well-maintained steam separators in the drum, a small amount of moisture escapes into the saturated steam.  This is known as mechanical carryover.  The S.C. guidelines above offer general limits to prevent excessive carryover, which we will touch upon again in the next section.  Note the much lower limit for the HP evaporator vs. the IP evaporator.  This is a direct influence of pressure.  Note that these are general guidelines.  Direct testing is necessary on every unit to determine the percentage carryover from the evaporator drums.     

Continuous pH measurement is critical.  The ranges shown provide general corrosion protection.  A sudden drop in pH indicates contaminant ingress, e.g., from a condenser tube leak, that must be promptly addressed.  A falling pH headed towards the 8.0 level requires immediate unit shutdown to prevent major damage, as this author can attest.  Confirmation of impurity ingress is readily available from CPD and feedwater CACE and sodium readings. 

The alkalinity provided by ammonia or amine injection to the feedwater network is not sufficient to protect against upset conditions.  Almost a century ago, chemists began employing sodium phosphates for boiler water chemistry control.  Treatment programs have gone through several iterations, but now, tri-sodium phosphate (Na₃PO₄) serves as the core boiler water treatment chemical in many drum units.  It provides needed alkalinity, thusly: 

Na₃PO₄ + H₂O ⇌ Na₂HPO₄ + NaOH (1) 

However, by the middle of the last century scientists discovered that control of phosphate concentrations is difficult due to the compound’s reverse solubility above 300^o F. 

The term for this phenomenon is known as “hideout.”  Hideout becomes increasingly problematic with increasing temperature, which explains the narrow phosphate range shown for the HP evaporator.  In today’s operating environment, where many units cycle up and down, or on and off, in load, hideout and the reverse effect as load is reduced can be quite challenging.   

Steam Monitoring

Steam purity measurements are very important, as contaminant deposition on turbine blades can lead to corrosion and possible blade failures, which represent a potentially catastrophic situation with the turbine spinning at several thousand rpm.  Table 4, Reference 2 guidelines are as follows: 

IP and HP Evaporator Saturated Steam 

• IP Sodium: < 3 µg/kg 
• HP Sodium: < 2 µg/kg 

HP Steam/Reheat Steam 

• CACE:  ≤ 0.2 µS/cm 
• Sodium: < 2 µg/kg 

Saturated steam sodium measurements provide a direct indication of mechanical carryover from the evaporator drums and can serve as a method to determine if boiler water dissolved solids concentrations are out of control.  Damage or failure of a steam separator(s) will also increase carryover.   

Regarding HP steam and reheat steam analyses, salts, and particularly chloride salts, will settle in the last rows of the low-pressure turbine, where they can cause pitting and subsequent stress corrosion cracking (SCC) and corrosion fatigue (CF) of turbine blades and rotors.  Sodium hydroxide carryover is a very serious issue, as caustic can quickly induce SCC of turbine components. 

CACE provides an indirect measurement of chloride and sulfate carryover, and the 0.2 µS/cm value has been a long-time guideline for turbine manufacturers.  However, the accuracy of CACE is suspect.  The recommended limit for both chloride and sulfate is 2 µg/kg, similar to sodium, but reports have periodically appeared that suggest significantly higher concentrations but with CACE still below 0.2 µS/cm. 

A relatively new instrument has emerged on the market that allows analyses of these two impurities down to a 0.1 µg/kg level. 

Although not shown in the table above, it has long been known that silica in steam will precipitate on turbine blades.  While silica can carry over mechanically, more problematic is vaporous carryover, especially at high pressures.  The compound is not corrosive, but it can influence turbine aerodynamics and reduce efficiency.  Comprehensive water/steam sampling systems often include steam silica analyzers, and sometimes also instruments for boiler water monitoring. 

An Undiscussed Issue

Space limitations prevented discussion of sample extraction and conditioning details.  These are critical items to ensure data reliability.  Information is available in Reference 9. 

Disclaimer

This article outlined important water/steam chemistry measurements for combined cycle HRSGs, but should only serve as general guidelines.  Every facility is unique and requires specific evaluations.  Much additional information is available in the references. 

References 

1. Buecker, B., “HRSG Steam Generation Issues: Reemphasizing the Importance of FAC Corrosion Control, Parts 1-4”; Factor This Power Engineering, September-October 2022. 

2. International Association for the Properties of Water and Steam, Technical Guidance Document: Phosphate and NaOH treatments for the steam-water circuits of drum boilers of fossil and combined cycle/HRSG power plants (2015). 

3. Shulder, S., and Buecker, B., “Remember the 3Ds of Alkalizing Amines: Dissociation, Distribution, and Decomposition”; PPCHEM Journal, 2023/01. 

4. Guidelines for Control of Flow-Accelerated Corrosion in Fossil and Combined Cycle Power Plants, EPRI Technical Report 3002011569, the Electric Power Research Institute, Palo Alto, California, 2017.  This document is available to the industry as a free report because FAC is such an important safety issue. 

5. International Association for the Properties of Water and Steam, Technical Guidance Document: Volatile treatments for the steam-water circuits of fossil and combined cycle/HRSG power plants (2015). 

6. Buecker, B., Shulder, S., and Sieben, A., “Fossil Power Plant Cycle Chemistry”; pre-conference seminar to the 39^th Annual Electric Utility Chemistry Workshop, June 4, 2019, Champaign, Illinois. 

7. Smith, J.B., and Craven, D.M., “Supplemental Oxygen for All-Volatile Treatment under Oxidizing Conditions”; PPCHEM Journal, 26/2024 – No. 6, November/December 2024. 

8. Buecker, B., Kuruc, K., and Johnson, L., “The Integral Benefits of Iron Monitoring for Steam Generation Chemistry Control”; Factor This Power Engineering, January 2019. 

9. International Association for the Properties of Water and Steam, IAPWS TGD2-09(2024), Technical Guidance Document: Instrumentation for monitoring and control of cycle chemistry for the steam/water circuits of fossil-fired, combined cycle, and industrial power plants (2024). 

About the author

Brad Buecker currently serves as Senior Technical Consultant with SAMCO Technologies.  He has many years of experience in or supporting the power industry, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Illinois) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kansas, station. Additionally, his background includes eleven years with two engineering firms, Burns & McDonnell and Kiewit, and two years as acting water/wastewater supervisor at a chemical plant. Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry.

He has authored or co-authored over 300 articles for various technical trade magazines, and he has written three books on power plant chemistry and air pollution control. He is a member of the ACS, AIChE, AMPP, ASME, AWT, and he is active with POWERGEN, the Electric Utility & Cogeneration Chemistry Workshop (now co-located with POWERGEN), and the International Water Conference. He can be reached at bueckerb@samcotech.com. 

On Monday, Nextpower completed its previously announced acquisition of utility-scale battery energy storage system (BESS) company Prevalon Energy, formally marking its entry into the storage market. The deal to fold in Prevalon, a U.S.-headquartered joint venture between Mitsubishi Power Americas and EES, was valued up to $365 million.

Nextpower now officially owns more than 6 gigawatt-hours (GWh) of energy storage systems deployed worldwide. Its integrated platform now extends far beyond Nextpower’s solar roots, offering a robust portfolio of storage, energy management software, power control technologies, and lifecycle services that support grid-connected storage, hybrid power plants, AI data center infrastructure, and other critical power applications.

“We are very pleased to welcome the talented Prevalon team to Nextpower. The team will continue to be run by Tom Cornell, who led Prevalon as CEO since its founding,” said Dan Shugar, founder and CEO of Nextpower.

“That continuity matters. Customers need partners that know the technology, understand the projects, and stay accountable long after commissioning,” he added in a post on LinkedIn.

According to Shugar, reliable energy storage is foundational to designing, building, and operating critical energy infrastructure. The addition of Prevalon will expand Nextpower’s ability to serve utility-scale customers and data centers with a broader portfolio of proven technologies and also provides Shugar with a significant foothold in one of the fastest-growing segments of the global power industry. Nextpower projects global demand for storage outside China could represent an opportunity of up to $35 billion by 2030, with the U.S. accounting for up to $15 billion.

“As demand for electricity accelerates, utilities, power producers, data center developers, and grid operators need accountable, bankable partners that can deliver reliable, dispatchable power at unprecedented scale and speed,” he stated. “With our customer-centric approach, reputation for high-quality execution, and proven ability to rapidly scale, Nextpower is uniquely positioned to serve both continued growth of utility-scale solar and the rapidly growing energy storage market.”

“That is the future we’re building toward,” added Shugar, sharing a photo of Prevalon BESS alongside Nextpower trackers (above). “Solar, storage, software, and field-proven execution working together.”

Nextpower’s Recent Acquisitions

Nextracker officially became Nextpower in November, 2025 to better reflect its position as an integrated power technology provider and distance itself from its reputation as a tracker company. Since mid-2024, the firm has been rapidly acquiring new business arms, including:

• Zimmermann PV-Steel Group ($378 million)
  In June 2026, Nextpower entered into a definitive agreement to acquire German solar technology company Zimmermann, which specializes in fixed-tilt structures, carports, high-density trackers, and floating PV systems. The deal significantly expands Nextpower’s structural product lineup and doubles its addressable market presence across Europe. Zimmermann was founded in 1950 and expanded into the solar industry in 2009, delivering more than 2,500 solar projects across 58 countries. Fixed tilt represents approximately 50 percent of Europe’s utility PV market today, according to S&P Global, especially in markets such as Germany, France, and Poland. 
  
  
• Zigor Corporation’s power conversion business / Apex Power ($80.5 million)
  In May 2026, Nextpower reached terms to acquire complementary assets of Zigor Corporation’s power conversion business and its U.S.-based subsidiary, Apex Power. The transaction is expected to enable rapid scale-up of inverter manufacturing capacity in the U.S., with production ramping up in 2027. It will also expand Nextpower’s product portfolio and capabilities in utility-scale solar power conversion and support its entry into battery energy storage and data center markets. The acquisition will include modular, field-deployed inverter technology and experienced engineering talent. The product technology is suitable for new battery storage and solar inverter applications at 1500V, repowering applications at 600V and 1000V, and is 2000V ready.
  
  
• Origami Solar ($53 million)
  In September 2025, Nextpower (then Nextracker) doled out $53M cash for roll-formed steel solar frame pioneer Origami Solar. Steel frames offer a high-performance alternative to traditional extruded aluminum frames, delivering superior strength and durability, competitive cost, a robust localized supply chain, and a significantly lower carbon footprint. Since folding in U.S.-based Origami, Nextpower has announced major commercial orders for steel modules, including a three-year, 1 GW+ contract with Jinko Solar US.
  
  
• Bentek Corporation ($78 million)
  In May 2025, Nextpower (then Nextracker) acquired U.S.-based Bentek Corporation, an industry pioneer and manufacturer of electrical infrastructure used in all types of solar power plants. Its pre-assembled eBOS solutions are now offered as standalone, industry-compatible components for both trackers and fixed tilt systems, as well as in formats optimized for use in integrated NX Horizon system solutions. Bentek’s U.S. fabrication footprint further enhanced Nextpower’s domestic supply chain position; its products include trunk buses, combiner boxes, configurable harnesses, and more.
  
  
• Ojjo ($119 million)
  In June 2024, Nextpower (then Nextracker) closed on an all-cash transaction to scoop up Ojjo, a developer of specialized ground-mount foundation technology. Ojjo’s patented truss systems are engineered for rocky or difficult soil conditions while using significantly less steel than standard foundations. Integrating Ojjo enabled Nextpower to offer a unified tracker-plus-foundation package to simplify engineering and construction for developers.
  
  
• AI and robotics suite ($40 million+)
  Nextpower (then Nextracker) bolstered its artificial intelligence and robotics capabilities with three acquisitions spanning 2024 and 2025, snapping up SenseHawk IP (AI drone mapping, 3D modeling, digital site commissioning), Amir Robotics (water-free robotic panel cleaning), and OnSight Technology (autonomous inspection and thermal detection robots).

Originally published in Factor This.