Decentralized Energy Systems: Toward Carbon-Neutral Energy Solutions for Gas Turbines

, compares decentralized systems to centralized heat and power units and highlights its advantages—including modularity, the possibility to exploit waste heat avoiding energy transmission losses, and reducing energy distribution costs. 

Giuseppe Tilocca, Scientific Officer at ETN Global, reviews these advantages in detail, as well as trends and emerging market opportunities. He also dives into gas turbines and how they fit into decentralized energy systems.

Q: Can you provide a background on ETN Global and its report on decentralized energy systems?

ETN Global is a non-profit association. We have OEMs, users, the R&D community, suppliers—the entire spectrum of stakeholders. We mainly work on technology, but we also delve into market and policy. We gather users’ challenges every year through high-level meetings and transform them into pathways for technical requirements.

Considering this specific report, we all know that the energy sector is transforming very quickly, and it’s mainly driven by the increasingly high share of renewable energy sources. In this scenario, which is dominated by variable sources, the demand for daily, weekly, and seasonal flexibility is set to grow dramatically. To meet the system requirements while accomplishing the ambitious decarbonization goals, we need to support traditional centralized generation with a mix of centralized components, such as demand response and stability generation. 

It is about going into the critical role of decentralized energy systems to achieve carbon-neutral energy solutions, particularly focusing on the integration and application of gas turbine technology.

Q: How do you define a decentralized energy system, and what is its advantage over centralized heat and power units?

Historically, we established centralized energy systems, meaning large plants located far from consumers. The reason behind it is merely economy of scale and efficiency, so it is cheaper to have one big plant than many small ones; however, with the increasing integration of variable renewable energy sources, which are inherently decentralized, we now need to adapt our infrastructure and incorporate technologies that are traditionally used for centralized energy. By definition, a decentralized energy system is located close to the consumption nodes—so on the end user side of the network—and therefore it’s connected to the distribution grid rather than the transmission grid.

The advantages of a decentralized energy system are mainly modularity, the possibility of exploiting waste heat, and a positive contribution to stability. One of the main benefits of being close to consumption nodes is avoiding transmission and distribution losses and costs compared to centralized generation. Decentralized energy systems are pivotal in meeting the pillars of the energy trilemma, which stress the principles of affordability, security, and climate neutrality and hence align with the requirements for the transition toward 2030 but also 2040 and 2050.

Q: What are the biggest hurdles that decentralized energy systems face?

There are three main hurdles. Technologically, it is scale. Smaller equipment is proportionally more expensive than larger equipment, as are installation costs. As a result, capital expenditure per kW installed is less competitive than for larger equipment. Similarly, operating expenses may proportionally increase as size decreases; this includes maintenance, onsite operations, and fuel costs. (Smaller units usually have lower fuel-conversion efficiency.) These two hurdles may somewhat balance the benefits of reducing transmission and distribution losses.

On the user side, one of the many hurdles is commitment. This applies to residential, commercial, and industrial sectors. Investing in energy isn’t necessarily seen as a priority—in many cases, it’s far easier to plug into the grid and forget about it. This is not the case when energy is a primary cost, or you need heat or mechanical power.

One of the most challenging aspects of decentralized energy systems is the integration of different energy sources, energy technology, and energy products—they all need to coexist. You could have variable renewables providing power; you could have storage during a surplus or need storage as a battery or fuel; or you may have flexible technology to ensure available power. Having many sources, technologies, and products presents a huge quantity of data to manage and, in such complex systems, integration and controls are among the biggest challenges.

Q: What are some trends and emerging opportunities identified by ETN Global in this space?

With the increasing penetration of renewables and decentralization, we often hear the word “flexibility”, which we define as power balance. To maintain electricity and meet demand in Europe, we’ll need more than double the current flexibility by 2030 and five times more by 2050. There are not many available, affordable, and scalable alternatives for gas turbines’ long-term flexibility, so this is a focus of ours.

Energy balance is only part of the problem, as many auxiliary services are of critical importance to maintain a reliable power supply. We see the market moving toward integrating smaller units or virtual power plants in auxiliary market services. These two factors are even more relevant if we consider congestion and bottlenecks in the power grid that will limit interconnection capacity and flexibility—this will require substantial investment.

A matter we often forget is energy includes not only electricity but also mechanical power and heat, which are inherently decentralized. Electrifying high-temperature heat presents several challenges, which is why gas turbines in decentralized energy systems will have a role in providing flexibility, auxiliary services, mechanical power, and heat.

Q: How do gas turbines fit into decentralized and carbon-neutral energy systems?

In terms of decentralization, gas turbines are recognized for their low maintenance, fuel flexibility, and compactness. Their successful applications include primary generation, continuous power, and standby power. In these applications, they leverage low maintenance, especially for remote locations offshore. They’re fuel flexibility means they are often used with waste fuels that other technologies may struggle to run, such as flare gas from oil and gas, biofuels, etc. Gas turbines also have the potential to provide waste heat for residential, commercial, and industrial cogeneration applications.

Small turbines can help in remote locations with no access to the grid or access to an unstable grid. They’re expected to play a significant role in emerging economies like Africa, where natural gas will drive industrial growth. Standalone generation will provide cost-effective electricity access for nearly one-third of Africa by 2030. Here, smart grids and microgrids present significant opportunities. An EU-funded project studied the impact of integrating decentralized energy systems, including solar, wind, gas turbines, hydrogen, and biogas, onto an island near Norway. 

Gas turbines’ carbon neutrality is not a matter of technology but fuel. Gas turbines can already use fuels like hydrogen, but the infrastructure for these fuels is missing.

Q: What are the advantages and struggles of gas turbines in these systems? What solutions and applications are addressing these issues?

Gas turbines enable flexibility. In decentralized energy systems, clean and dispatchable solutions such as gas turbines enable the energy transition—in fact, there is no energy transition without dispatchable solutions. We’re now seeing the role of gas turbines change rapidly in decentralized energy systems—moving from 8,000 operating hours per year to about 1,000 and from two to three cycles per year to two to three per day. This operational change will impact energy systems both economically and technically.

On the technical side, new market requirements will affect maintenance and operations. The R&D community is working on fuel flexibility to minimize emissions like NOx, which will position dispatchable, affordable gas turbines as sustainable and clean technologies for the energy trilemma.

Listen to the full podcast with Giuseppe Tilocca at 

ETN Global takes a deep dive into decentralized energy systems—advantages such as modularity, roadblocks for integration, and the future of power demand—and the role of gas turbines in a decarbonized future.

Q&A: Gas Turbines and Decentralized Energy Systems

During this episode of the TurboTime Podcast, Klaus Brun and Rainer Kurz discuss how hydrogen is transported and its use as an energy carrier. They then discuss how ammonia is produced, its advantages and limitations, and for what industries it’s a suitable solution.

“We’ve previously talked about hydrogen in some of our Myth Buster podcasts and how it’s relevant to a decarbonized energy economy as an energy carrier. Unfortunately, hydrogen itself has a lot of nasty characteristics: it's hard to compress, highly flammable, as a gas it’s not easy to deal with, etc. From a transportation and storage perspective, it leaks, has many safety issues, causes hydrogen embrittlement, etc., making it difficult to transport.”

“Making ammonia is nothing new. We know how to how the process works, but it is an energy-intensive process. But ammonia is a very toxic gas. It causes skin burns rapidly if you touch it in liquid form. In vapor form, even at less than 100 PPMs, it’s very irritating, so it creates a lot of issues from the handling perspective.”

In this episode of the TurboTime podcast, Myth Buster Klaus Brun and Rainer Kurz discuss ammonia. 

TurboTime Podcast: Ammonia with the Myth Busters

GE Aerospace signed a maintenance, repair, and offload (MRO) offload agreement with the Cyprus-based United Aerospace Maintenance Co. (UAMCO). The contract will quicken the work scopes for CFM LEAP engines and allow GE Aerospace to satisfy its MRO capacity and open ecosystem obligations for CFM. The ecosystem includes:

CFM internal capacity delivered by GE Aerospace and Safran Aircraft Engines

External capacity from Premier MRO workshops

External capacity from competing third-party MRO providers

“UAMCO offers a set of MRO capabilities and capacity,” said Tom Levin, Vice President of CFM Commercial Programs at GE Aerospace. “We depend on strategically located providers like UAMCO to help us meet unprecedented demand for LEAP engines, decrease turnaround time, and maintain the highest standards of safety and quality.”

Headquartered in Larnaca, Cyprus, UAMCO obtained EASA approval for quick-turn maintenance for LEAP-1A engines installed on Airbus A320neo fleets. The company also received MRO approval for LEAP-1B engines equipped on Boeing 737 MAX aircraft. UAMCO will fulfill the engine maintenance requirements of customers in Europe, the Middle East, and Africa.

Currently, the company is partnered with GE Aerospace On-Wing Support to perform on-wing and near-wing retrofits for the updated reverse bleed system in LEAP-1A engines. UAMCO employs two teams that can perform installations globally.

CFM LEAP 1-A aircraft engine; image credit: GE Aerospace

GE Aerospace’s CFM LEAP engine portfolio delivers 15% improved fuel efficiency and lower carbon emissions over CFM56 engines—operators record up to 20% savings compared to earlier aircraft. The LEAP engine surpassed 60 million flight hours in eight years and, with over 3,500 LEAP-equipped aircraft in service, CFM customers avoided more than 35 million tons of CO

“This agreement validates our commitment to safety, quality, technology, and to a spirit of cooperation between the Republic of Cyprus and the United States,” said John Savvides, Chief Executive Officer at UAMCO. “CFM LEAP engines power the world’s most popular passenger aircraft, and we look forward to working with GE Aerospace on the maintenance of these engines.”

Last week, GE Aerospace and Waygate Technologies, a subsidiary of Baker Hughes, developed an 

 for commercial engines. The companies focused on using AI to enhance machine vision-based assisted defect recognition (ADR). They targeted high-pressure compressor inspections because they are among the most important and time-consuming MRO tasks.

The AI-assisted features will improve the inspection workflow and deliver greater reliability by reducing the learning curve for new inspectors and helping current inspectors identify previously difficult-to-detect defects. Users are expected to see an increased detection probability and a reduction in inspection-related mental fatigue. In addition to improvements over the Gas Power-assist ADR model, the automated data anonymization tool enables the protection of sensitive partner data and allows it to be added to the training dataset.

In late October, GE Aerospace announced that it will invest over 

 in its MRO and component repair facilities in Europe. The planned investment, part of the company’s $1 billion MRO spending surge approved in early 2024. The company aims to meet the increasing demand for services between GE Aerospace and CFM1 installed base. These funds will support engine test cells, new equipment, and new technology such as AI-powered enhanced inspection techniques. The AI enhancements will reduce turnaround times and expand component repair capability.

United Aerospace Maintenance Co. will fulfill the customers’ CFM LEAP maintenance needs in Europe, the Middle East, and Africa by conducting on-wing-support and near-wing retrofits.

GE Aerospace Offloads Aviation Engine MRO Work to United Aerospace Maintenance

The power industry is exploring several avenues to decarbonize power plants, including implementing carbon capture and storage (CCS) technology; however, retrofitting power plants means high operational and capital costs, i.e., total costs. GE Vernova has been exploring ways to reduce these costs and the overall footprint of a carbon-capture system through its exhaust gas recirculation (EGR) system, which increases the concentration of CO

“CCUS can be added to existing power generation plants; however, any CCUS project must look at the plant holistically to be more successful during integration. It is crucial to focus on integration with all systems, including gas turbines, heat recovery steam generators (HRSG), steam turbines, and plant controls,” said Jeremee Wetherby, Carbon Solutions Director at GE Vernova.

GE Vernova completes FEED studies on how to reduce carbon emissions for three power plants in the Kingdom of Saudi Arabia.

In October 2024, GE Vernova’s front-end engineering design (FEED) study, 

Retrofittable Advanced Combined-Cycle Integration for Flexible Decarbonized Generation

, found the effects of adding a system capable of capturing up to 95% of CO

 emissions at a combined-cycle power plant in Alabama could be reduced through a series of integration measures, including an EGR system. The study findings, released by the U.S. Department of Energy’s Office of Fossil Energy and Carbon Management, found integrating GE Vernova’s EGR system:

could reduce more than 6% of the total cost of the carbon-capture facility compared to installing carbon capture without the EGR system

could reduce total carbon-capture operational costs per year (total costs include reductions to capital and operating costs)

According to GE Vernova, the benefits of an EGR system compared to a non-EGR system include:

a large reduction of carbon-capture facility footprint and cost of absorber

lower operating costs due to reduced amine degradation

less energy-intensive separation due to higher concentration of CO

more steam turbine power output due to lower steam consumption

“Think of a slider bar where CapEx reductions are at one end and operational benefits (including costs and capture rate) are at the other end,” Wetherby said. “If owners slide that bar toward CapEx, EGR can enable them to reduce the size of the capture equipment, which can reduce its land footprint and cut costs while maintaining up to 95% capture. Operators who harness EGR-enhanced carbon-capture systems can make capital-expense savings of up to 10% including a performance boost."

“At the other end of the slider bar, an operator could calibrate its equipment to achieve more decarbonization, boosting the total carbon capture of its project from 95% up to 98%,” he continued. “That’s because the EGR system would increase the carbon concentration of the air at inlet entry from approximately 4% to 7%. It just depends on how the capture plant is engineered.”

GE Vernova completed FEED studies in collaboration with Ash Sharqiyah Operations & Maintenance Co.

 at three cogeneration plants in Saudi Arabia.

The 7E and 7F gas turbines, with modifications to their standard combustors, can already operate with hydrogen blends up to 100%. These FEED studies explored solutions to enable the use of blends including natural gas and hydrogen, with hydrogen accounting for up to 32% by volume. In addition, the studies established the required combustor system modifications to achieve this level of hydrogen blending.

This FEED study showed that integrating its EGR system could reduce more than 7% of the carbon-capture facility’s total cost compared to a facility without EGR. It also showed a 6% reduction in carbon-capture operational costs annually.

Looking forward, GE Vernova is planning to extend its advanced controls used to operate gas and steam turbines to operate the CCUS in such a way as to maintain the operating flexibility that customers may depend upon.

Jeremee Wetherby, the Carbon Solutions Director at GE Vernova, offers deeper insights into the benefits of retrofitting carbon-capture systems with an exhaust gas recirculation system.

Exhaust Gas Recirculation Boosts Carbon-Capture Efficiency and Reduces Costs, says GE Vernova

The gas turbine market for electrical generation has been and will continue to be stable barring any unforeseen circumstances, such as the 2020 pandemic, that affected many markets. That said, the major players such as Siemens Energy, Mitsubishi Power, and GE Vernova still hold the majority of the market value. Major trends will likely not affect turbine production itself, as production rates remain stable for now. Forces like hydrogen use, digitalization, and renewable energy have the potential to be market-altering, but to what degree is uncertain.

Gas turbines offer a promising avenue for decarbonization through their adaptability to hydrogen fuel. However, the transition involves significant challenges, including:

While existing turbines can be retrofitted with hydrogen-compatible burners, the combustion characteristics of hydrogen differ significantly from natural gas, necessitating modifications to ensure efficient and stable operation. The economic viability of hydrogen-fueled gas turbines is also influenced by the initial investment in retrofitting or purchasing new units, in addition to the cost of hydrogen itself. Transporting hydrogen will be a factor as well, either pipelines or an on-site hydrogen production facility will be necessary. Digitalization also has a role in the future of gas turbine technology.

The integration of digital technologies is revolutionizing the operation and maintenance of gas turbines. Utilizing sensors, data analytics, and artificial intelligence, operators can gain valuable insights into turbine performance and health. Predictive maintenance algorithms can anticipate potential failures, allowing for proactive maintenance and minimizing downtime.

Digitalization also enables remote monitoring and control, reducing the need for onsite personnel and improving operational efficiency. Furthermore, digital twin technologies can create virtual replicas of gas turbines, providing a platform for testing different operating conditions and optimizing performance. Gas turbines can also be leveraged for use in conjunction with renewable resources.

Hybrid systems—gas turbines combined with renewable energy sources such as solar or wind power—offer a powerful solution to address the challenges associated with energy production. These systems leverage the complementary strengths of both technologies, providing reliable baseload power from gas turbines and intermittent clean energy from renewable sources.

reduce reliance on fossil fuels, contributing to a cleaner energy future 

What does all this mean? Gas turbines have the potential to gain even more popularity than currently, but will that offset the unused capacity already installed worldwide? The Irsching Power Station in Germany, for example, is reportedly running only one out of three units at the plant. Hydrogen, too, has its opponents: A recent report from the Institute for Energy Economics and Financial Analysis suggests that hydrogen might not be the best way forward for gas turbines.

Therefore, balancing the potential gain in popularity among energy companies and the public with the unknowns of hydrogen’s future in this market and the issue that many turbines are not being fully utilized translates to a stable market in this analyst’s eyes. No massive swings in the market are foreseen at this time.

, the value of the gas turbine market for electrical power generation will remain stable moving forward. The most popular turbines will fall in the 250 - 500 MW output range (

), with GE Vernova, Siemens Energy, and Mitsubishi Power holding the position of top-three manufacturers (

As an example of the current stable market, Forecast International’s (FI) Industrial & Marine Gas Turbine Installations Database lists 105 SGT5/6- 8000H turbines ordered, with most being installed now. Installations, and therefore orders (FI lists install years as orders are announced), are at about two to five per year. This has not changed significantly since 2018 when many of Siemens Energy’s machines were installed worldwide. This trend extends to other models.

In conclusion, gas turbines will have a place in the future of power generation. Hydrogen and other technologies, although promising, will not likely affect overall production, as current machines can be utilized instead of installing new capacity, and the future of these technologies remains to be seen.

Carter Palmer is an Industrial & Marine Turbine Analyst at Forecast International, a provider of market intelligence forecasting, proprietary research, and consulting services for the aerospace, defense, and power systems industries.

The gas turbine market is stable and will remain so among factors such as hydrogen, digitalization, and renewable energy.

Worldwide Gas Turbine Forecast 2025

This spring, near the end of a momentous term, the U.S. Supreme Court overturned a four-decade-old bedrock regulatory precedent that granted deference to subject-matter experts at regulatory agencies.

In deciding Ohio v. E.P.A., the high court upended the process by which future, and potentially past, regulations would be determined for energy, the environment, vehicle safety, and food and drug safety—indeed the broader economy. The overturned case was one of the most-cited cases in federal regulatory law: Chevron U.S.A., Inc. v. Natural Resources Defense Council.

Well before the high court’s July 1 ruling, Republican presidential candidate Donald Trump had repeatedly vowed to reverse, block, or at least defund many if not most of President Joe Biden’s energy and environmental initiatives. The Republican National Committee platform, adopted in July, included planks calling for the abolition of the electric vehicle (EV) “mandate,” cutting burdensome regulations, and “making America the dominant energy producer in the world, by far.”

Then, over the summer, as Biden’s support fell apart, he bowed out of the race and endorsed Vice President Kamala Harris as the candidate to succeed him, creating a completely different electoral dynamic for November.

The results of the November elections—for the presidency, one-third of the Senate, and all 435 members of the House of Representatives—will likely have an outsize impact on companies that own and operate electrical generation assets in the United States as well as those who build or service those generators.

However the elections conclude, events in the months preceding them should give pause to those who thought the United States was on a one-way trip to a carbon-free electric future:

The U.S. Supreme Court ruling in Ohio v. E.P.A. overturned a 40-year-old precedent in which experts in regulatory agencies were granted deference in crafting regulations when Congressional intent was ambiguous or unclear.

FirstEnergy became the latest electric utility to delay the planned retirement of coal-fired generators, joining PacifiCorp, WEC Energy Group, Alliant Energy, Dominion, Santee Cooper, Omaha Public Power District, and Evergy. The list may grow longer as utilities grapple with the soaring electric demand growth coming from data centers, particularly those powered by artificial intelligence (AI).

Google, Microsoft, and other tech companies disclosed that they no longer were on a net-zero trajectory, as the energy consumption of their data centers effectively erased years of their use of renewable electricity.

 emissions grew in the developing world more than offsetting reductions in developed economies.

In a highly unusual move, the Supreme Court stayed the EPA's "Good Neighbor Rule" on air emissions, even as it was still being litigated by the lower courts.

2023 went down in the record books as the hottest in recorded history, and 2024 appeared on track to break that record. Extreme weather events—fueled, experts say, by global warming—are becoming more extreme, more frequent, more destructive, and more expensive.

The Texas grid operator Electric Reliability Council of Texas (ERCOT) estimated there was a 12% probability of rolling blackouts this summer, as dramatically faster electric demand growth coupled with a shortfall of dispatchable generation caused the agency to question its own ability to provide reliable electricity to Texans.

Biden’s EPA finalized a suite of Clean Air Act regulations, sure to be challenged by Republicans, sharply lowering emission standards from existing coal-fired power plants as well as future gas-fired generators. A separate rule, covering emissions from existing gas-fired generators, is expected later this year. That, too, is expected to draw legal challenge.

Another executive-level agency, the Council on Environmental Quality, finalized changes to reform, update, and streamline the environmental review process in the National Environmental Policy Act (NEPA), another foundational piece of federal environmental regulation. Again, this final rule is almost certain to be challenged by GOP attorneys general and other parties, regardless of how power is apportioned in Washington, D.C., in 2025.

Throughout the spring, Biden’s regulatory agencies worked to finalize rules on a wide variety of energy and environmental issues in the hope they could withstand challenge under the Congressional Review Act (CRA), a GOP-enacted measure that allows Congress to overturn any executive-agency regulation that was finalized within 60 legislative days of a presidential election. A majority vote in both houses is all that is needed to repeal any regulation enacted in the 11th hour of an outgoing presidential administration.

The key is legislative days, not calendar days. Congress was not in session for large chunks of June, July, and August, which moved the 60-day “lookback” date to as early as May 20, according to the Congress watchers at Arnold & Porter. 

George Washington University’s Regulatory Studies Center reported that federal agencies published 66 significant final rules in April, covering all manner of issues, higher than any month since the Reagan administration. 

So yes, it was a busy run-up to the November elections. And no matter what the outcome of the 2024 election, it looks like 2025 will be a busy one for the U.S. new-build power industry.

On taking office in 2021, President Biden confirmed his goal of cutting CO

 emissions to zero for the power sector by 2035 as a first step to decarbonizing the entire U.S. economy by 2050.

For the domestic new-build power generation industry, the rush to renewables was well underway years before Biden placed his hand on the Bible on Jan. 20, 2021. That trend continued during 2024. In the United States, about 71 renewable energy projects were completed through July, and another 200 were scheduled to begin construction during the remainder of 2024, according to data tracked by Industrial Info Resources (IIR). The value of those completed projects is about $11.6 billion while the value of the second-half projects is nearly $53 billion.

Looking forward to projects beginning construction during 2025 - 2029, IIR data shows only a slight slowdown in the rush to renewables: Approximately 91% of all power projects beginning construction during that time will be renewable, down slightly from earlier trends (

The 2022 Inflation Reduction Act’s commitment of $369 billion in federal funds to new-build renewable energy significantly strengthened the longstanding trend of heightened investment in new non-emitting electric generation. 

That longstanding trend has been buttressed not only by federal money but also by the growing competitiveness of renewable electric generation and state lawmakers’ and regulators’ pronounced preference for non-emitting generation.

An adjacent Biden policy initiative, to spur the sales of electric cars and trucks, may also significantly impact new-build generation. At press time, the EV initiative appeared to be falling short of initial estimates, but results vary from state to state. California is still expecting a jolt to electric demand from electric transportation, but other states seem to be scaling back expectations.

Electric car and truck sales are on track to number roughly one million units in 2024, down from 2023’s sales of 1.6 million units. The slower-than-expected uptake caused the administration to revise its timeline for new, stricter new vehicle tailpipe emissions.

Previously rosy projections of EV sales had caused many electric utilities to boost their planned capital expenditures (CAPEX) to cover bulking up their electric distribution system so that it would not be overly stressed when clusters of EV owners came home from work and recharged their vehicles at the same time.

Like many other assumptions about the power industry, the slow uptake of EVs is causing some utilities to rethink their planned higher CAPEX spending to strengthen and expand their distribution networks.

But offsetting this trend is the sharp growth in demand from data centers, particularly those equipped with AI. Several utilities with data center clusters in their service areas, such as Dominion, Georgia Power, American Electric Power, and Public Service Electric & Gas, have been forced to increase their projection of electric demand growth, and thus CAPEX to build new generation.

Some, but not all, of this new generation is slated to burn natural gas, but because many data center owners have signed sustainability commitments, IIR expects a good bit of this new generation will be renewables plus storage.

This year, electric reliability organizations, such as the North American Electric Reliability Corp. (NERC) and ERCOT, sounded alarms about whether electric generation will be sufficient to meet rising peak demand. Those concerns no doubt played into plans to dramatically increase new-generation construction projects in the United States.

Developers have sharply increased their planned construction kickoffs for all forms of generation for 2025 - 2029, according to data tracked by IIR. In analyzing prior five-year kickoff plans, data we tracked showed developers planned to begin construction of about 200 GW of new generation in the United States over successive five-year periods starting in 2011 (

But in recent years, those plans have sharply accelerated. In IIR’s most recent analysis of U.S. planned generation construction starts, covering 2025 - 2029, about 875 GW of new-build generation is scheduled to begin turning dirt, roughly four times the prior five-year period. This data includes all types of electric generation.

IIR does not expect all these planned generation projects will begin construction as slated. Many will be deferred, and some will be canceled outright. However, tracking power plant development suggests that many new projects will be added over the next five years.

Another factor influencing types of new-build generation construction is the continued influence of “sustainable” investing among institutional investors, pension funds, and other types of financial asset managers. A growing number of asset managers have pledged to abide by the U.N. Principles for Responsible Investment (PRI), which rules out investing in new coal generators and frowns on new-build gas generation. Through March 31 of this year, organizations that managed over $128 trillion in funds have signed onto the UN PRI, continuing a yearslong rise (

In mid-2024, when FirstEnergy CEO Brian Tierney told the 

 the multistate utility holding company was abandoning the planned 2030 phaseout of coal-fired generation, he observed, “Some people think we were bad people for doing that. I think … we’re just honest.” 

FirstEnergy operates 10 electric distribution companies that provide electricity to six million customers in five states in the Midwest and Mid-Atlantic regions. It also operates two coal-fired power stations in West Virginia with about 3,082 MW of combined generating capacity.

FirstEnergy’s operating utilities operate in the PJM Interconnection, a power market that includes northern Virginia, the world’s largest data center hub. Electricity demand in the PJM region is one of the fastest growing in the country, the 

 reported, with the operator this year more than tripling its growth forecast for the next decade.

“When we were looking at emissions reduction, it was based on running our coal-fired power plants less at the end of the decade,” Tierney said. “We don’t see a pathway for that now.” 

He cited exceptionally strong electric demand growth, driven by existing and planned data centers in the Old Dominion state and elsewhere.

“The things that are bumping up against each other are people’s growing demand and desire for reliability, what’s affordable for most customers, and then what’s sustainable. It’s easier to make two of those three things congruent with one another. It’s harder to get all three solved at the same time,” Tierney told the 

Tierney’s not the only utility chief struggling to balance the energy trilemma: reliability, affordability, and sustainability. But forced to make a choice, it appears he is willing to sacrifice sustainability to deliver reliability and affordability.

Those who lead electric utilities hold electric reliability as a foundational, non-negotiable element of their mission. It’s the reason electric utilities exist. Everything else—safety, affordability, economic development, and, more recently, sustainability—comes after reliability. To meet soaring electric demand, they will use any and all resources at their disposal, starting with the most economical ones first.

As the cost of renewables has fallen steadily in recent years, utilities have embraced wind and solar. The hundreds of billions of dollars in federal support for renewables contained in the 2022 Inflation Reduction Act didn’t hurt, but the embrace of wind and solar was well underway before that law was passed. 

Even as they embraced intermittent, non-emitting generation like wind and solar, some utility leaders did so grudgingly, mindful that the wind doesn’t always blow, and the sun doesn’t always shine. But regulators supported renewables, and what regulators want, they usually get.

One other trend we noticed this year: More asset owners were deferring the planned closure of coal-fired generators. At the start of 2024, IIR tracked nearly 5 GW of planned retirements for U.S. coal-fired generators, but by midyear, that slipped to about 3 GW. It may fall faster in the last months of the year. 

We expect the decision to close, or defer closing, coal-fired generation may lead to questions from regulators, lawmakers, and consumer groups. If that comes to pass, we expect utility leaders to say, in effect, “Increased CO

 emissions were preferable to rolling blackouts.”

Since 2010, over 150 GW of U.S. coalfired generation has been retired, forced by tightening environmental regulations, increasingly competitive natural gas prices, and the declining cost of renewables. Looking out over the next five years, IIR is tracking the planned closure of about 56 GW of coal generation (

Presidential elections are typically important for the power industry, but few in recent memory stack up to the potential consequences of the 2024 election.

U.S. Power Industry Outlook 2025

The 2024 Turbomachinery & Pump Symposia (TPS), held Aug. 20 - 22 at the George R. Brown Convention Center in Houston, boasted over 4,500 attendees and more than 300 exhibitors. Organized by Texas A&M’s Turbomachinery Laboratory, attendees from over 50 countries gathered to hear engineers, directors, and managers discuss optimizing compressor anti-surge control systems, integrating CO

 capture plants, bottoming cycles, and more.

George R. Brown Convention Center in Houston, TX. Credit: Adobe Stock

Presenters from Compressor Controls Corp. (CCC) and Petrobras hosted a paper presentation, 

Optimizing Compressors Anti-Surge Control

 to Reduce Power Consumption and Greenhouse Gases Emissions in Oil Production Units

, analyzing the energy and carbon performance of compressor anti-surge control systems on existing offshore platforms in the Brazilian pre-salt fields.

According to Fabio Jacinto Zanetti De Souza, Brownfield Account Manager at CCC: “The primary function of the anti-surge control system is to prevent the centrifugal compressor from operating under surge conditions, which is a potentially damaging phenomenon for the compressor. However, the secondary functions of an anti-surge control system are often overlooked or unaddressed by many providers. It can help maintain specific suction pressure in centrifugal compressors through a Ps limit loop or prevent reaching a high discharge pressure through a Pd limit loop. The system also avoids high discharge temperature that could lead to a trip due to high Td or manipulate the anti-surge valve for periodic stroke tests and send operators an alarm if the valve demonstrates some level of stickiness. The anti-surge control can also be used to avoid critical speeds during startup of an expander-recompressor arrangement in natural gas liquids plants or even prevent overspeed.”

Pedro Barbosa, Turbomachinery Advisor at Petrobras laid out several challenges with running a gas compressor on a floating production, storage, and offloading (FPSO) vessel in the Brazilian pre-salt fields:

Gas compressors are the largest power consumers and greenhouse gas emitters aboard an FPSO vessel  

FPSOs have highly variable operating conditions over unit lifecycle  

Following startup, gas compressors are difficult to tune  

Pre-salt FPSOs contain complex plants with high CO

 content, affecting compressor curves and surge lines

Barbosa addressed further compressor difficulties that could be assisted by anti-surge control. “When the unit is treating gas for exportation, it passes through a CO

 removal plant to the export compressors, then to a gas pipeline,” said Barbosa. “The compressors begin to work in a non-flow-sharing mode, meaning that one machine can be used for exportation and the other rejects non-treated gas. The machines begin to compete, with one increasing flow and the other decreasing— this is when surge control becomes important.”

According to Serge Staroselsky, Chief Technology Officer at CCC, Petrobras leveraged an anti-surge control system to achieve multiple performance benefits: equipment protection, improved efficiency, increased reliability, and enhanced safety.

Anti-surge systems detect when a compressor is approaching surge conditions and take corrective action to prevent the condition from occurring. By preventing surge, these systems can help to reduce the frequency and cost of maintenance and repairs.

They can help to optimize compressor operation by maintaining their most efficient point, thus reducing energy consumption. Minimizing unnecessary power output keeps gas compressors from emitting large amounts of CO

The systems reduce compressor downtime and improve overall plant productivity and process stability. Controlling system margins, such as anti-surge valve performance and flow measurement signal quality, can also reduce gas recycling.

Surge can lead to dangerous conditions, such as sudden pressure surges or vibrations. Anti-surge systems can help reduce the risk of accidents and improve overall safety on FPSO vessels. 

Following anti-surge control integration, “We calculate the operating point of the machines, we calculate power, and then we assess anti-surge valve closing to see how much we’ll save,” said Staroselsky. “After the calculations, we reduced the margin by 5% and, in the minimum case, saved 170 kW of power. In the maximum case, during operation over the entire year, we could generate around 500 kW in potential savings.”

Combining optimized turbomachinery controls with the appropriate energy and carbon-performance management system help decarbonize offshore operations, “by ensuring that energy consumption and emissions are minimized through precise control and monitoring,” De Souza said. “Optimized controls enhance the efficiency of turbomachinery, reducing the power required for operation, while the performance management system tracks energy use and carbon emissions in real-time. This integrated approach allows for continuous adjustments and improvements, ensuring that operations remain as efficient and low-emission as possible, ultimately leading to significant reductions in the carbon footprint of offshore oil production units.” 

After utilizing the compressor anti-surge control system, De Souza said the reduction in recycle flow on the Petrobras project would lead to an overall efficiency increase of 4%. “On an FPSO powered by gas turbogenerators, it will reduce fuel-gas consumption by 630,000 standard cubic meters per year. The carbon emissions saved with this optimization would reach 1,600 tons of CO

 per year. All these numbers are calculated for a single 11-MW compressor train—an FPSO contains five to six of these trains.”

The industry is familiar with carbon-capture technologies’ ability to remove CO

 from flue gas streams. Still, the challenges of providing the flue gas in the correct conditions and supplying the energy required for the CO

 reviewed the most common types of carbon-capture technologies and explored how open-cycle gas turbines could achieve similar results.

Mike Welch, Industry Marketing Manager at Siemens Energy, said gas turbines can achieve decarbonization by firing low-carbon fuels and their plants can be equipped with post-combustion capture technology. Despite these carbon capabilities, users typically favor traditional technologies over gas turbines for capture applications, citing low CO

 concentration in exhaust (3 - 4%) and high exhaust gas temperatures as the primary challenges.

He outlined several considerations for choosing carbon-capture technologies, including:

Impact of NOx and SOx on solvent life and replacement rate

According to Welch, carbon capture is a difficult process when using gas turbines: “The only certain thing about CO

 capture is that you’ll need a lot of space, and it’ll cost you a lot of money—it’s not a cheap solution. Most processes are designed to operate at low ambient temperatures, so you become limited to the available technologies when operating with a gas turbine. There are only a few that don’t require cooling of the gas turbine exhaust and most of the emerging technologies can’t support large-scale turbines.”

Despite the inherent challenges of running current carbon-capture technologies in conjunction with gas turbines, there are many available systems in use today. The most common are amine-based systems, which utilize proven solvents to absorb CO

 with low toxicity and low energy demand for desorption. However, these solutions have large footprints and long construction times, with higher energy demand for absorption.

Often applied to smaller emitters that generate less than 1,000 tons of CO

 per day. With a smaller footprint, towers have shorter construction times and can be used at space-constrained sites, such as offshore platforms.

 adsorption through centrifugal force, but generally lower capture rates at approximately 100 tons per day.

Proven for gas processing and scalable to large CO

 capture volumes. The energy demand is similar to amine towers, but these systems can use hot water for solvent desorption. On the downside, potassium carbonate operates with low flue gas inlet temperatures.

Unlike typical potassium carbonate, it operates at high flue gas temperatures in a pressurized process. It can generate its own electricity and gas turbine supplementary firing can increase CO

These are also proven for gas processing but struggle when applied to gas turbines, as multiple modules are required to achieve the desired capture rate and purity. Membrane contactor modules are a hybrid solution combined with amine solvents.

Electro-swing adsorption can be used on gas streams with any CO

 concentration and, according to electrochemical operators, can selectively capture NOx and SOx.

Lukas Biyikli, R&D Portfolio Manager of Integrally Geared Compressors at Siemens Energy, outlined the basics of CO

 compression and utilization processes following capture. Although compression is the primary electricity consumer in carbon-capture plants, it is a critical step for transportation via pipeline—the most economical way to move CO

 from point A to point B. The main equipment for compression applications is reciprocating, single-shaft, and integrally geared compressors.

Although compression is the primary electricity consumer in carbon-capture plant, it is a critical step for transportation via pipeline—the most economical way to move CO

 from point A to point B. - Lukas Biyikli

Biyikli pointed out: “Through heat recovery from compressors, hot water for district heating or process steam up to 10 bar is available via heat exchangers by adapting the compressor design slightly. There is a great synergy between the heat and steam demand that conventional amine-based capture systems have and the steam provided by the compressors since amine systems typically require high amounts of saturated steam between 3 and 6 bar—in range of what the compressor can deliver. Siemens Energy’s concept provides up to 80% of the steam demand for an amine system while only increasing the power requirement of the compressor by onesixth of that heat provided compared to conventional compressor operation, which means a coefficient of performance of up to 6.0 for the system.”

Performance of Industrial Gas Turbines and Bottoming Cycles

, led by Karl Wygant, Senior Manager at Ebara Elliott Energy, Klaus Brun, Director of Global R&D at Ebara Elliott Energy, and Rainer Kurz, Principal of RKSBenergy, discussed control strategies and performance characteristics for the engine compressor, combustor, and turbine section. 

In addition to covering energy flow concepts between turbine components, the panel outlined control concepts for single- and two-shaft machines, driving generators, compressors, and pumps. Bottoming cycle performance is also discussed, with methods to use performance data for trending and comparison analyses.

Brun led the discussion on gas turbine thermodynamics, which began with descriptions of both enthalpy and entropy. “Enthalpy has many definitions, but from the easiest perspective it’s energy per unit/ mass or how much energy you have in the process fluid, which is air in a gas turbine and water in a steam turbine. Entropy can be described as the second law of thermodynamics. If entropy is very high, you have a lot of losses in the system.”

Gas turbine thermodynamic cycles are typically based on the Brayton cycle, which consists of four main processes:

The working fluid (usually air) is compressed in a compressor, increasing its pressure and temperature.

The compressed air is heated in a combustion chamber by burning fuel, increasing its temperature at constant pressure.

TPS 2024 tackled the latest challenges, solutions, and technologies in the turbomachinery industry.

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