Emerson is a global technology and software company headquartered in St. Louis, Missouri. It provides solutions across multiple markets and process industries, including power, oil and gas, and downstream hydrocarbons, among others. This includes technologies to manage, control, and optimize turbomachinery asset operation.

“Our portfolio includes automation & control software for turbomachinery operating in the power generation and process industries,” said Jim Nyenhuis, Manager of Performance Consulting for the Power Industry at Emerson. “More specifically, we provide turbomachinery control systems, supervisory control and data acquisition (SCADA), condition monitoring, and safety systems complemented by operations management software for asset and operations performance, data management and digital twin simulation.”

In addition, the company offers digital solutions for predictive AI-driven maintenance, remote monitoring, automated operational decision-making, and cybersecurity services designed to identify vulnerabilities, close protection gaps, and secure process control systems before an attack threatens to impact operations. For functional safety (SIL), it offers SIL3-capable safety systems together with an in-house expert team for SIL implementation on turbomachinery applications. The SIL safety system is integrated with the Emerson control system.

Fleetwide, plantwide, and remote controls are available with the Emerson Ovation platform.

Nyenhuis noted several evolving trends associated with the transformation of the broader energy landscape to net zero and aggressive decarbonization. Reliance on renewables, for example, brings new challenges when working with intermittent power sources: That, in turn, requires greater asset flexibility and the necessity to closely monitor assets that operate differently than originally intended.

Workforce transitions, too, are exerting a significant impact on the industry: The accelerating loss of skilled technical workers due to Baby Boomer retirements, the mass resignation phenomenon coming out of the pandemic, and the influx of a digital native workforce generation. Combined, these factors bring to the forefront the need to address how organizations can operate and maintain equipment and facilities when faced with reduced staffing equipped with varying levels of hands-on experience.

Additionally, there is increasing interest in leveraging digitalization and data analytics taking root in an environment where many plants continue to operate with controls and automation systems of varying vintages from varying suppliers. This can impact both reliability and efficiency. It can be difficult to locate spare parts and personnel with the expertise to conduct the needed services for multiple outdated systems.

“We help customers implement digital strategies by taking small data-driven steps,” said Jim Nyenhuis, Emerson. “We do this by providing control applications, wireless solutions, condition monitoring, digital twin simulation and data analytics.”

The modern plant environment calls for several elements: Quickly recognizing and responding to changing operational conditions for improved plant performance and flexibility; improving load flexibility by increasing ramp rates; better unit cycling performance and consistency; more robust and stable minimum load operation; and a decrease in the number of forced outages by reducing equipment stress.

New tools are emerging to help personnel make sense of the massive amounts of data they now collect. These tools and algorithms monitor equipment as well as process efficiency and health. When paired with various machine learning techniques and AI-based diagnostic solutions, the resulting intelligence can be used to predict and better manage potential failure situations.


Accordingly, Emerson offers a unified automation and software platform known as Ovation that helps to eliminate complexity and risk by capturing and contextualizing process and operational data.

“Ovation automation technology enables secure, reliable power plant, and equipment operation,” said Nyenhuis. “Emerson’s five decades of power generation expertise is embedded within Ovation software and technologies to form a digital platform that optimizes plant and equipment performance while reducing operations and maintenance costs.”

A single platform provides full power plant control, optimization, digital twin simulation, and analysis of all generating assets including major equipment, individual units, or multi-plant fleets. The software is also designed to incorporate renewable and distributed energy sources into the energy mix. It extends beyond the bounds of traditional distributed control and data acquisition systems to include integrated vibration monitoring, generator excitation control, safety instrumented systems, scalable footprints for small or distributed applications, virtualization, and embedded simulation.

Specific to the turbomachinery sector, Ovation Machinery Health Monitor integrates machinery protection and condition monitoring into an Ovation control system. The module snaps into the existing I/O base to provide continuous online monitoring of vibration and other machinery health parameters with orbit, waveform, and spectrum analysis display capabilities. Instead of alarms being generated after damage has occurred, Ovation HMIs display alerts based on sensor peak and phase values as well as Emerson PeakVue readings for rolling element bearings. Connecting the module to Emerson’s AMS Machine Works application provides condition monitoring capabilities outside of the Ovation network. A defense-in-depth approach to cybersecurity is built into the platform.

The Ovation platform monitors vibration and other machinery health parameters.

“The stress placed on rotating equipment can introduce premature component wear and other thermal and mechanical-related issues,” said Nyenhuis. “Failure events can develop slowly and quickly escalate to failure with little to no warning, putting the safety of plant operations and staff at risk. Vibration and asset monitoring solutions identify developing faults well in advance of breakdowns.”

Such technology is also being implemented in fields such as hydrogen generation, carbon capture and storage (CCS), and energy storage. For example, Mitsubishi Power America’s Advanced Clean Energy Storage Hub uses renewable electricity to power electrolyzers to produce green hydrogen. The hydrogen is then stored in salt caverns and dispatched when required to the Intermountain Power Project (IPP Renewed) to generate electricity from hydrogen-fueled turbines. Emerson is providing an integrated Ovation control and safety platform to optimize the hub’s production efficiency and help ensure safe operations.


Remote, real-time access to operations is more critical than ever, especially with the increase of geographically dispersed and often unmanned assets. Emerson has made progress in the establishment of remote operations centers. Control software detects the onset of an abnormal condition and alerts the operator to take action to avert potential problems. Plant data can also be sent to a centralized monitoring and diagnostics (M&D) center for longer-term, strategic analysis across the entire fleet.

“Remote and mobile capabilities enable secure and efficient access to data from anywhere at any time,” said Nyenhuis. “This enables faster and more precise responses to critical issues, as well as the ability to proactively address maintenance issues, minimizing costs and improving safety.”

For compressor drive units, for example, progress has been made integrating the compressor and prime mover controls for easier operation and maintenance and to streamline cybersecurity protection. Such gains are enabled by many factors, including advancements in the speed and bandwidth of networking technologies.


Digital transformation is being embraced across the industry as organizations seek to boost operating efficiency, decrease downtime, and reduce costs. Advances in Internet of Things (IoT) and automation technologies are opening the door to greater levels of digitalization.

However, Nyenhuis cautions those engaged in digital transformation that while a game-changer, it can also be a disruptor. It is not only about technology.

“Organizations are increasingly factoring in not only process and technology, but also their culture—seeking buy-in from the people who will be interacting most with the technology,” he said. “This last element, commonly overlooked in the past, is essential for successful digital transformation.” 

OVATION AUTOMATION & CONTROL SOFTWARE FOR TURBOMACHINERY 

VENDOR SPOTLIGHT: EMERSON

Figure 1: With six LM6000 units commissioned ahead of Winter Storm Uri by EPC contractor ProEnergy, the HO Clarke Generating Station generated continuous power to meet emergency capacity needs. Courtesy of ProEnergy.

Winter Storm Uri crippled infrastructure across the United States in February 2021. Texas was particularly hard hit: reports estimate that 69% of residents lost power and financial losses totaled $130 billion. No single generation type can take responsibility for the catastrophic blackouts. Instead, the least resilient facilities across all types of generation led to 60% less available capacity in the ERCOT market.


However, a new plant in Houston, Texas—a result of designing specifically for resilience—proved reliable in the historic storm. HO Clarke Generating Station (Figure 1) was created to meet the demands of typical Gulf Coast heat and increasingly common cold snaps. Owned by independent power producer (IPP) WattBridge, the plant leveraged a standardized design that enabled the 6xLM6000 facility to be commissioned two months ahead of schedule and fortuitously, a week before the storm began. The facility remained available throughout the weather event.

Figure 2: The LM6000 icing envelope puts power plants at risk below 40°F (4.4°C). Courtesy of ProEnergy.


Policymakers and industry experts agree that fast, flexible, and dispatchable power is necessary for grid firming. In the United States, most major utilities rely on gas peakers to augment their coal retirements and support their growing renewables portfolio.


Aeroderivative gas turbines—the prevailing peaking power technology—are valued for full power fast starts in less than 10 minutes; low turn-down for loads with low unit emissions compliance; rapid load following of up to 25 MW/min, per unit; and minimal maintenance penalties for frequent starts. They offer modular power output, flexibility, efficiency, and reliability.
A single 300-MW frame turbine drops in efficiency and produces higher emissions when operating at 50% turndown. A six unit 300 MW aero facility, in comparison, can operate three units at full load. In the event of a turbine failure, only 17% of the total output is lost.


But aero peakers face economic hurdles as they operate with a low capacity factor, impacting revenue projections. This can make project financing difficult. One way around this is to stick to a standardized plant design and have a ready supply of replacement turbines available. This approach can deliver competitive installed costs.


Combustion turbine-generator (CTG) packages must be designed for both cold and hot conditions: anti-icing systems drive resilience in cold weather operation and power augmentation maintains output in hot weather operation.


In cold weather, the goal is keeping the facility online; a plant in Texas, however, will not require the same strategy as one in Minnesota. Anti-icing systems—traditionally overlooked in warmer climates—ensure sustained cold weather operation. Turbine icing begins at 40°F (4.4°C) (Figure 2), which means that most facilities in the world may experience icing at some point.


Though located in the warm Gulf Coast, the HO Clarke site is equipped with a package air recirculation system (Figure 3). It draws heated air from the engine compartment and recirculates it to the inlet air module. The system leverages waste heat from the turbine compartment and uses existing package exhaust fans to eliminate icing with minimal parasitic output losses.


Several other anti-icing technologies can be used to address turbine icing. These include compressor discharge pressure (CDP) bleed air recirculation, exhaust gas recirculation, and glycol heater and coil system. Regardless of the type of technology, any system only needs to raise the inlet air temperature by 5 to 10°F to eliminate icing risk.

Figure 3: The ProEnergy anti-icing system recirculates heated air from the engine compartment for zero parasitic losses. Courtesy of ProEnergy.


For balance of plant (BOP) winterization, designers must balance operational strategies and procedures with costs. HO Clarke used water line recirculation, temporary insulation jackets, and temporary electrically heated enclosures. BOP designs should also minimize single-point failures that can reduce power output to include sufficient water and backup fuel storage, facility winterization, redundancy, and civil seismic/wind rating. Besides these package and BOP considerations, a comprehensive operations strategy, coupled with remote monitoring and diagnostic capabilities, helps to ensure continuous availability.


In hot weather, the goal is to maximize power output or minimize lapses in power output.


Turbine output is directly related to relative humidity and inversely related to temperature: as temperature increases, power output decreases. At 100°F (38°C) and 30% relative humidity, the base performance of an LM6000 engine degrades from 50 MW to approximately 27 MW (Figure 4). By implementing power augmentation strategies, such as low-pressure water-spray power augmentation, inlet fogging, evaporative cooling, and inlet chilling and coils, power can be returned to nameplate capacity.

Figure 4: Together, chilling, inlet fogging, and low-pressure water spray can augment LM6000 power to nameplate capacity despite high temperatures. Courtesy of ProEnergy.


Developers should carefully select power augmentation technologies to optimize the power benefit against CAPEX and OPEX. Factors to consider: Water-spray technologies and inlet fogging both require a consistent flow of demineralized water; evaporative cooling requires a separate, higher conductivity water feed, and causes increased static pressure on the turbine inlet, which results in efficiency loss; inlet chilling and coil systems tend to be both complex and costly. Given the annual number of hot Texas days combined with an ample supply of demineralized water, HO Clarke opted for water-spray augmentation and inlet fogging as the best way to maintain nameplate output.


Firm gas supply and adequate pressure are essential to resilience. Peaking facilities built on under-pressured fuel lines typically depend on gas compressors, which add significant expense in addition to a being a common operational point of failure. Because gas supply and gas compression can impact the economic validity of a project, designers must seek strategic access to reliable gas lines as was done with HO Clarke.


Implementing dual-fuel operations can bolster facility resilience. Using diesel fuel backed by adequate storage can provide valuable operational flexibility in emergency situations. Independent System Operators (ISOs) like ERCOT and PJM now provide guidance on days of fuel storage required.

Implementing dual-fuel operations can bolster facility resilience.

Given the potentially long-duration runs in the Gulf Coast of Texas, a 375,000-gallon water tank was added at HO Clarke that supports facility operation for approximately 14 hours. Concrete pads were also added for any needed rental demineralization trailers to augment existing systems.


Additionally, there are electrical design considerations needed to address redundancy and failures. This can include selecting how many turbine-generator packages should feed a generator step-up transformer, a well-thought-out breaker and disconnect switch configuration, and the use of double-ended switchgear. Emergency systems must be configured for the intended response strategy—whether to safely shut down or to continue with normal operations. In addition, blackstart capability can provide a means to get back online independent of a utility backfeed, as well as enable owners to improve project economics by participating in that ancillary service.


As extreme weather events—such as heat waves, droughts, wildfires, polar vortexes, and floods—challenge grid stability, the world will likely need an “all-of-the-above” solution to grid resilience. These include transmission infrastructure expansions, demand response management, long-duration energy storage, and alternative fuels. No matter the solution, peaker plants with resilient designs will remain the backstop to grid stability. ■

Ammar Moosa is Director Commercial Operations at ProEnergy. He holds
a BASc in Chemical Engineering from the University of Waterloo and an MEng in Chemical Engineering from the University of Toronto. For more information visit proenergy services.com or email amoosa@proenergyservices.com

DESIGNING AERODERIVATIVE PLANTS FOR RESILIENCE

POWER RESILIENCE

Components made at the Innovation Center.

Siemens Energy has expanded its Innovation Center in Orlando, Florida. As the company’s first global hub for innovation, it is dedicated to accelerating the development of products and solutions to drive the energy transition through collaboration, rapid prototyping, and testing.

Siemens Energy Innovation Center CTO Cliff Hatcher showcases new 3D printing techniques being applied to blades.

The company has spent more than $30 million over the last few years in building its research & development operations in Florida. Another $7 million during 2022 added an extra wing as well as equipment for the machine shop, further additive manufacturing (AM) machines, and more robotics to inspect and repair components for equipment like turbines capable of running on hydrogen. The expansion increases the space from 17,000 sq. ft. to 30,000 sq. ft.

“We operate with a start-up mentality, where ideas that used to take six months to test now take six weeks,” said Rich Voorberg, President, North America for Siemens Energy.


Turbomachinery International visited the center during its grand opening in October 2019. On our return in September of 2022, it was immediately clear that things had changed considerably. The company has substantially increased its manufacturing capability, increasing the volume of work in terms of man hours by around three times. A tour highlighted the fact that further space reorganization was ongoing to make room for yet more equipment.

“We have skills in-house that span mechanical engineering, electrical engineering, AI, welding, and a multitude of other disciplines,” said Voorberg. “We need all kinds of machinery to hand so we can develop prototypes rapidly and efficiently.”

Cliff Hatcher, CTO of the Innovation Center, led the tour. He said that the center was originally an experiment to see the effect of putting experts from multiple disciplines under one roof. Based on its success over the past three years, similar centers are being established in Berlin, Abu Dhabi, and China. In addition to new product and process developments, they will function as showrooms for what Siemens Energy is doing in the field of transformative technology.

“We wanted to be agile and have a footprint that could change as market needs changed,” said Hatcher. “We can work on one topic this week, and pivot immediately to another as required.”

AM represents a recent pivot. The center is working more extensively with AM to streamline the supply chain for 3D printed parts. It will help determine which parts should be made where based on quantity and complexity, as well as prototyping new parts to be printed and developing new techniques and processes. The company is also involved in the White House’s AM Forward initiative to help small businesses learn and adopt AM. This is just one facet of a shift from being a purely internal operation to using the center to engender creativity with customers and across the supply chain.

A customer site in South America, for example, had a legacy guide vane that was damaged during the disassembly process. The manufacturing plant no longer had the capability to make the part on an expedited schedule. After an exhaustive search for an existing part the service team ran out of options to meet the outage time schedule. They turned to Innovation Center Orlando to manufacture a new part that would meet the outage schedule of 15 days. The Innovation Center team 3D printed a replacement and shipped to their manufacturing facility in Charlotte to finish machining. In parallel, the center also machined a part from a block of steel on its 5-axis CNC machine. The parts arrived on time, costly damages were avoided, and the customer met its outage schedule.


During the tour, we previewed work being done to make the 3D printing of blades feasible. Previously, 3D printing was only really viable for smaller parts due to the process involved: a layer of metallic powder of about 40 microns is laid down and laser sintered then another layer and another. For larger parts subject to high stress and temperatures such as blades, the center is using Wire Arc Additive Manufacturing (WAAM). It lays down 20 mm layers of molten metal at a time. The process is being refined and requires a lot more finishing than traditional 3D printing.

Rich Voorberg said customers are keen to co-fund and co-create projects such as blade advances as well as in carbon capture, hydrogen, and other areas of the energy transition.

“Some customers are working with us to push turbine development to be able to run on 100% hydrogen,” he said. “The challenge is not so much in burning hydrogen but in establishing the entire hydrogen supply chain.”

Easier said than done. Hydrogen supply is extremely limited. Siemens Energy has developed electrolyzers and is working to scale up green hydrogen production. The recent infrastructure package enacted into law provides a $3 per kilo green hydrogen incentive, which will help ease funding stress on this technology. Nevertheless, we are looking at a long runway before hydrogen or some other fuel will replace natural gas.

“The amount of hydrogen you need to burn in large gas turbines is incredible,” said Voorberg. “We see the most viable market for hydrogen power being in areas such as buses, trains, and forklift trucks. But we will gradually see more hydrogen being blended with natural gas where it is available and economical to do so.” ■

FOCUS ON ADDDITIVE MANUFACTURING, PROTOTYPING NEW TECHNOLOGIES, AND DECARBONIZATION

SIEMENS ENERGY INNOVATION CENTER

Turbomachinery International recently toured Mitsubishi Power’s Orlando Service Center. Established in 2001 and expanded in 2008, the facility serves as a repair, service, and manufacturing center. The tour began in the Tomoni Hub which monitors more than 100 gas turbines throughout the Americas.


The Tomoni Hub leverages remote monitoring, digital control systems, predictive analytics, and AI to optimize power plants. It is the hub that provides support beyond monitoring. Operations specialists provide technical and operational assistance to customers 24/7. The Tomoni Hub also acts as a channel to O&M support for on-site personnel by providing real time operational support for the monitored fleet.

Prasanth Thupili, Senior Vice President of Power Generation Services at Mitsubishi Power Americas, said that the Tomoni Hub used to almost exclusively monitor gas turbines. But it now offers total plant monitoring including steam turbines and generators.


“We can do remote tuning and troubleshooting using augmented reality (AR) technology,” he said.


The Tomoni Hub receives a constant stream of data and metrics from its fleet. If something unusual is observed, combustor dynamics can be monitored and perform tuning remotely.


On the repair side, multiple in-house processes are offered. These include STEM machining (an acid electrolytic drilling technique), electrical discharge machining (EDM), milling, welding, brazing, thermal coating spray, coating removal, heat treatment, and various kinds of non-destructive examination (NDE).

Air plasma spray at Mitsubishi Power in Orlando


The extent of the facilities was a big surprise. The entire center comprises a manufacturing and repair facility totaling about 190,000 ft2. The Mitsubishi Power Orlando Service Center manufactures vanes, blades, and compressor blades totaling approximately 15,000 parts per year.


“We manufacture turbine Row 1 and 2 blades in Orlando as these are the hot-test parts,” said Thupili. “The other rows are manufactured in Japan.”
He oversees an operation that includes gas turbine, steam turbine, and generator parts, fields service, specialty repairs, and an exchange program. He noted that the steam turbine service and repair business has picked up recently. This is due in part to delayed outages due to the COVID-19 pandemic.
“We have seen a surge in the scope of our steam turbine services to include a lot more onsite inspections and more unplanned work that needs to be done on blades and other components,” said Thupili.

Electrical discharge machining (EDM) at Mitsubishi Power in Orlando


The business has also taken on the role of servicing electrolyzers, including 40 massive Mitsubishi Power hydrogen electrolyzers that are being installed in the ACES project in Utah. That will involve onsite inspections when the facility commences operation in 2024. He doesn’t anticipate the need for shop inspections of these machines until around 2030.

Laser ablation at Mitsubishi Power in Orlando


“Customers want us to do more auxiliary work beyond the normal scope of gas turbine, steam turbine, and generator repair,” said Thupili. “They prefer a single entity to do everything rather than dealing with multiple parties.”
He noted that flexibility has become just as important to customers as reliability. Some want to reduce the load on their units, sometimes as low as 35%.

Fuel nozzle inspection and repair at Mitsubishi Power in Orlando


With the labor market being so tight these days, the company is investing in more robotics and tools so that its workforce can become more productive. Examples include a robot that can remove ceramic coating from parts and small robotic tools to check the health of generators during field inspections. These inspections are done in between the rotor and the stator.


“With this tool, we no longer need to take out the rotor,” said Thupili. “Instead of ten people needed for an on-site inspection and repair, it only needs a couple.” ■


ORLANDO SERVICE CENTER PROVIDES BLADE/VANE MANUFACTURING AS WELL AS REPAIR AND REMOTE MONITORING SERVICES

MITSUBISHI POWER

The gas turbine power generation market is on the way to some normalcy after a decline in the mid-2010s and the COVID-19 pandemic. With recovery in prospect, the shift to greener machines is underway with the major turbine players announcing increasing amounts of hydrogen to power their turbines. Siemens Energy, General Electric, and Mitsubishi, in particular, are developing burners to adapt to a natural gas and hydrogen mix or even pure hydrogen. With that said, gas turbines will be needed moving forward to augment renewables, especially in North America and Western Europe. Gas turbines will continue to see advances in efficiency and will remain attractive options for power production.


This Forecast International market analysis of gas turbine-powered electrical generation projects that sales over the period 2022-2031 will total $117.087 billion. This is indicative of a recovery in the gas turbine electrical power generation market. The recovery from the mid-2010s was somewhat thwarted in 2020 by the COVID-19 pandemic. As COVID-19 hampered all activity for a time, the pandemic should be seen as a blip in terms of turbine production and not a lasting effect.

Gas turbines are expected to generate about $10 billion in sales in 2022. This is forecast to climb gradually to more than $12 billion by 2031.

Hydrogen’s entry into the market should not be understated, and is becoming an attractive option as a fuel for gas turbines. Green, blue, or gray hydrogen can be used to power turbines. Green hydrogen especially can be produced in a carbon-neutral manner. When a turbine burns pure hydrogen, it emits no particulate or carbon monoxide emissions. This means the machine can be a renewable supplier of energy if the infrastructure is there to transport the gas.

Either electrolysis for onsite hydrogen or pipelines are needed to make hydrogen a reality in running gas turbines. According to some sources, a natural gas pipeline can transport a mix of up to 15% hydrogen with little modification. Higher mixtures would need adaptation. Over the mid and long-term, the industry will be dominated by large combined-cycle facilities in the industrialized nations, notably Japan and countries in Europe and Asia.

The number of gas turbines produced will increase steadily between 2022 and 2030. This is the first time in a great many years that the industry has been forecast to experience steady expansion.

The 250-500 MW and 500-750 MW turbine classes dominate the industry in terms of dollar value. If anything, this trend will strengthen as the decade progresses.

A major impact in the U.S. and Western Europe has been the emphasis on conserving energy and adopting energy efficient alternatives to existing equipment. For example, consumers have been urged to switch from the old-style incandescent lightbulbs to compact fluorescent lightbulbs (CFLs) and to LED bulbs. The cost savings are significant for the homeowner. In addition, it smooths out the spike in demand that takes place when people come home from work.

Changing user consumption profiles is a worldwide phenomenon, although the motivation may differ from region to region. In Europe and America, the primary driver is to reduce electricity demand and thus reduce pollution and eliminate potentially harmful emissions. In other areas, the economic benefits of new, power-efficient technologies are the leading driver, placing electrical equipment within the reach of people who otherwise could not afford to run it. This will work to increase popular demand for available and reliable power supplies. Thus, the same basic consumer trends that will depress demand for additional generating capacity in some regions will increase it in others.

GE Energy is predicted to remain top in terms of market share in overall gas turbine revenue over the next ten years. It represents 38% of the pie, followed by 25% for Siemens Energy, Mitsubishi Power with 18%, and Ansaldo Energia with 5%. Together, these 5 companies will account for more than 80% of gas turbine revenue between now and 2031.

Europe, Asia, and North America are now roughly equal in terms of their percentage of the value they represent in international gas turbine sales.

 The impact of improved distribution and control networks is continuing to blur the distinction between baseload capacity and the rest. Only nuclear-powered generation is unequivocally considered baseload due to its long run times at steady-state load. In contrast, fossil-fuel plants are experiencing a different pattern of operation that exhibits frequent starts, load-following, and shutdowns to meet seasonal demands. As quick-reacting gas turbines replace steam machines, this trend is likely to continue.

However, it is well understood that the majority of breakdowns happen when a plant is either started up or shut down. This evolving operational profile is likely to increase the frequency of outages and the cost of procuring replacement parts. In parallel, sales of G-,H-, and J-class machines are increasing as utilities place more importance on efficiency and vendors accumulate operational experience with new designs.

Germany, France, and other countries are moving away from nuclear and focusing on renewables. Existing natural gas capacity will likely not be augmented, but will probably not be shut down. There are currently plants sitting idle but some may be brought back online. However, Russia supplied a majority of Europe’s gas. With the ongoing war, supplies of natural gas cannot be taken for granted. Norway can pick up some of the slack and run at increased output until 2030. It remains to be seen how the natural gas situation develops in Europe.

Electricity generation is rising in Eastern Europe, including Romania, Poland, Slovenia, Bulgaria, and Czech Republic. Aging coal plants are being replaced with combined-cycle natural gas plants. Renewables are not as prevalent in comparison to Western Europe; however, combined cycle plants will likely lay groundwork for more renewables.

 Southeast Asia’s energy demand is projected to grow by 80% by 2040 as the regional economy triples in size and population rises by almost a quarter to 760 million. As a result, it is likely that oil demand will rise from 4.7 million barrels per day in 2024 to 6.8 million b/d in 2040. At the same time, natural gas use will grow by almost two-thirds to around 265 billion cubic meters. In sharp contrast to other regions, coal demand will greatly expand and overtake oil to become the largest fuel. Renewables will make inroads but should decline from 26% of the fuel mix to 21%. The share of fossil fuels will rise to 78% by 2040.

India and China are the two most populous countries in the world by a wide margin. Both are short on electrical power. The generation capacity is inefficient and a major cause of pollution, while grids are incomplete and lack proper coordination and administration. As in Eastern Europe, coal plants will be replaced by natural gas.

In summary, Forecast International predicts that the importance of gas turbines will not diminish over time. More efficient machines will continue to be produced and hydrogen will play more of a role, although how big of a role 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. Forecast's Platinum 4.4 information and analysis service was used to compile this report. For more information, visit www.forecastinternational.com

POSITIVE SALES PROJECTION FOR THE NEXT DECADE

GAS TURBINE FORECAST 2023

Methane from flaring, leakage, and other fugitive emissions is now public enemy number one on the environmental front. Courtesy of Shutterstock

The U.S. Environmental Protection Agency (EPA) and other regulatory bodies around the world are turning their attention to the policing of fugitive emissions from sources such as fuel leakage, unburned methane, and other greenhouse gases (GHG) sources besides those related directly to the combustion process. A big reason for the surge of interest in methane is that it is said to be anywhere from 20 to 90 times more potent than carbon dioxide as a GHG (depending on the time frame considered). Thus, it has been labelled as environmental danger number one.

The Inflation Reduction Act, for example, reduced the amount of allowable methane leakage to 1% and placed a fee of up to $1,500.00 per ton for excess methane. Canada, too, has passed methane emissions reduction rules for upstream oil and natural gas facilities. These encompass extraction, primary processing, transport, storage, leakage from compressors, and fracked gas wells.


Natural gas producers, transporters, plant operators, and the industry in general, therefore, can expect the pressure to ramp up on the monitoring, measurement, and capture of fugitive methane emissions. Previous efforts centered around the minimization of methane flaring. The latest rules, standards, and net zero commitments take things to a whole new level.


The vendor community is responding. Solutions are coming to market that measure the amount of methane that spills out from oil & gas sites, detect various sources of fugitive emissions, capture any leaked methane and reuse it in combustion and other processes, and provide better sealing technology for pipelines and compressors. It is becoming important, too, to be able to report how much methane comes into a facility and compare it to how much is burned and recaptured.


“Natural gas, which is primarily composed of methane, has been regarded as a pollutant as well as a commodity since 2016 based on standards targeting oil & gas operations,” said Brian Kromer, Managing Director and Principal, Step2Compliance. “Controls must now be able to accurately calculate GHG emissions as well as the conventional pollutants. Facilities must learn to track the amount of methane leakage and find ways to recapture it and put it to use.”


Some are even flying airborne infrared spectrometers over oil & gas production basins in attempt to quantify methane point sources. They measure wavelengths in light to estimate the amount of methane. Some say their estimates are questionable. But inflated or not, they will be used to condemn production facilities. The best response is to do everything possible to prevent leakage.


Here are some of the things the vendor community has evolved to address this issue:


EagleBurgmann has developed RoTechBooster technology to reduce methane emissions. If compressors are stopped frequently, dry gas seals may become contaminated. This can be avoided by depressurizing the compressor housing. However during this process, large amounts of methane can escape. To avoid this and maintain pressure in the compressor housing during downtime, a rotating seal gas booster can be used such as RoTechBooster. It is an electrically driven seal gas booster that keeps dry gas seals clean during standby conditions, and at any time insufficient seal gas flow occurs. Its rotating design allows the compressor to be placed in a pressurized hold for nearly unlimited time. No venting or flaring is required.


The company has also released the CobaDGS zero emission compressor seal. In higher pressure applications such as natural gas compressors, conventional tandem dry gas seals are typically used to minimize leakage of natural gas/methane. Due to their tandem design, they meet safety requirements, and reduce emissions by up to 90% compared with oil-lubricated compressor shaft seals. In addition, less friction occurs, and the service life is longer. Nevertheless, tandem dry gas seals still leak some methane into the atmosphere during operation. Another possibility to eliminate seal leakage is to use dry gas seals in double arrangement supplied with nitrogen (N2). However, this seal configuration is less safe and only approved for low pressures. Besides, if the N2 supply is interrupted, the double seals can get damaged.


“For the CobaDGS dry gas seal, EagleBurgmann adapted the coaxial design of its CobaSeal for use at higher pressures,” said Benjamin Hellmig of EagleBurgmann. “The Cobaseal is a separation seal is a coaxial design that is also supplied with N2 but is resilient to gas supply interruptions. It can remain pressurized with N2 during operation and shutdown without contamination.”


Matthias Grapow, Vice President Business Intelligence and Business Development, MAN Energy Solutions, believes that producing biogas from organic waste will grow rapidly in the coming years. The company’s HOFIM-based Factory LNG technology is used at organic waste collection sites where biomethane (aka renewable natural gas) can be liquefied from biogas. Biogas or biomethane can be used for combined heat and power (CHP) operations or turned into electricity. This approach can also be used for small-scale LNG to enable natural gas to be supplied to places not directly tied to a mainline natural gas pipeline.

HOFIM high-speed oil-free integrated motor-compressor by MAN Energy Solutions


“Through a fleet of cryogenic transport tanks, the produced LNG can be transported over long distances by truck or trains to enable the provision of energy to isolated regions,” said Grapow.


The hermetically sealed and electrically driven compression HOFIM consists of a single rotating element, two radial and one axial bearing, no couplings, no gearbox, no lube oil and no shaft seals to atmosphere. These zero emission compressors are suitable for use in midstream gas transport, gas storage, small-scale LNG, upstream subsea, and topside compression.


“Instead of flaring production-related gas losses, the gases can be reused within the process for power or heat generation, or can be converted into transportation fuel or LNG,” said Grapow.


Tom Harper, Vice President, Emissions Management and Commercial Development Leader, Climate Technology Solutions at Baker Hughes, believes that the global oil and gas industry can eliminate 40% of its methane emissions at no net cost. It has developed various tools to meet this challenge.


The company’s Lumen Terrain and Lumen Sky technologies, for example, use analytics to detect, localize, and quantify methane leaks. This information can be used to prioritize recommendations for abatement, as well as supporting the verification of emissions reductions.

The emissions profile of gas turbines, particularly methane emissions is much better than reciprocating engines. Courtesy of Siemens Energy.


Another abatement solution is flare.IQ. It enables higher-efficiency flare combustion and reduced methane slip emissions. The Egyptian Ministry of Petroleum and Mineral Resources is deploying it in the refining sector in Egypt.


“This will lower flaring emissions from oil and gas operations by digitalizing emissions management infrastructure and pulling information about flare systems, substantially reducing emissions by ensuring a higher-efficiency flare combustion rate,” said Harper.


Siemens Energy’s flagship methane offering is the Spontaneous Leak Detection Service (powered by ProFlex) for gases, liquids and multi-phase fluids transported through pipelines. It utilizes signal processing on edge computing devices, Internet of Things (IoT) software, and data processing algorithms to identify leaks in near real-time.


“Our technology can detect leaks as small as ½ inch to 2 inches within seconds and provide accurate localization to as little as +/- 20 feet, while minimizing false positives,” said Anand Sengupta, Vice-President, Head of Global Sales,
Siemens Energy Compression.

The company has also developed predictive analytics technologies and digital twins that are used in Predictive Emissions Monitoring Software (PEMS) across the Siemens Energy small gas turbines portfolio. It helps operators predict regulated emissions accurately.


“Although methane slip or unburned hydrocarbons (UHC) in the exhaust of gas turbines is orders of magnitude lower compared to other engines, we’ve received many queries from customers, and are planning to incorporate the prediction of UHC into PEMS for small gas turbines,” said Sengupta


ABB has released of HoverGuard, an addition to its ABB Ability Mobile Gas Leak Detection System. HoverGuard is an Unmanned Aerial Vehicle (UAV)-based system that detects, quantifies and maps leaks up to 300 ft from natural gas distribution and transmission pipelines, gathering lines, storage facilities, and other potential sources. It automatically generates digital reports that summarize results and can be shared in minutes after a survey.


The cloud-connected, multi-gas solution quantifies the three most important greenhouse gases (methane, carbon dioxide and water vapor) continuously while flying. Cavity-enhanced laser absorption spectroscopy detects methane with a sensitivity more than 1,000 times higher than conventional leak detection tools. It can detect leaks while flying at altitudes of 130 ft or higher, and at speeds greater than 55 mph.

Enclosed Vapor Combustors (EVCs) are available from several vendors. They are being used, for example, in some Canadian gas facilities to address leakage at compressor and meter stations. Burners convert methane into water vapor and CO2. Testing has shown this technology to be 99.6% efficient in converting methane.


Klaus Brun, Director, Research and Development, Elliott Group, said his company is using technologies from others to improve methane emissions along its product line.


“We can utilize leak-free dry-gas seals or seal vent gas capture and recovery when a client requests it,” said Brun. “Our new 140 TCH pipeline compressor has a single dry gas seal instead of two seals to reduce dry gas seal leakage by 50%.”


He noted, though, that the biggest reduction in GHG emissions from compressors can be achieved by improving compressor efficiency or by converting the driver from an engine/gas turbine to an electric motor drive. Another way to lower methane spillage is to avoid shutdowns for blowdowns. That entails improving reliability and availability and eliminating false alarms.


Solar Turbines, too, is doing a number of things to reduce methane emissions. The company uses a system that gathers the leakage from dry gas seals and recompresses it back either to fuel gas pressure or compressor suction pressure.


ExxonMobil has reduced U.S. unconventional methane emissions by approximately 40% as of year-end 2021 when compared to 2016 by conducting tens of thousands of leak surveys and eliminating all its high bleed pneumatic devices. The company has developed ground-based continuous sensors, as well as aerial, airplane and satellites technologies to help with methane reduction.


“By 2030, we’re planning a 20% to 30% reduction in corporate greenhouse gas intensity, a 70% to 80% reduction in corporate methane intensity, and a 60% to 70% reduction in corporate-wide flaring intensity,” said Matt Kolesar, Chief Environmental Scientist at ExxonMobil.


BP has targeted zero routine flaring emissions by 2025 in its U.S. onshore operations and globally by 2030. It is deploying a variety of detection and monitoring technologies and is phasing out remaining pneumatic controllers.


Teledyne Flir’s FLIR GF320 detects hydrocarbon and volatile organic compound (VOC) emissions from natural gas production and use. With this optical gas imaging camera, inspectors can check components and see potential gas leaks in real-time. The GF320 is lightweight, offers both a viewfinder and LCD monitor, and has direct access to controls. Embedded GPS data helps in identifying the precise location of faults and leaks.

The ABB drone can detect leaks and measure gases


Vortex Services of Canada offers the Vortex Emissions Target Solution. It packages a elements that address methane measurement such as a fuel measurement, fuel valves, a display panel, sensors (O2 and NOx) a catalyst monitor, and several venturi elements to improve the fuel/air mix.


Continental Controls Corp. (CCC) offers a range of fuel control, fuel measurement, and emissions monitoring tools to accurately measure GHGs. Its Catalyst Monitor continuously measures pressure across the catalyst as well as pre- and post-catalyst temperature and notifies the user if minimum or maximum temperatures are exceeded. When combined with the CCC Air Fuel Ratio Controls (AFRC), it can make corrections to set points to maintain low emissions levels and extend the useful life of catalysts. This arrangement can be used to provide evidence of engine compliance and fuel consumption over an extended period of time.


“CCC continuously measures the true rate of methane compliance,” said Kromer. “Its tools can help monitor methane related to the exhaust as well as fugitive emissions.”

The Continental Controls Catalyst Monitor continuously measures pressure across the catalyst as well as pre- and post-catalyst temperature


Utilities, owners, operators, and plant personnel are grooved in to measuring emissions in the exhaust, but not methane.


“Methane is not easy to eliminate and doesn’t go away when you use a three-way catalyst,” said Rick Fisher, Vice President at Continental Controls Corp. “Every compressor station and any plant running a gas turbine or gas engine is going to suffer methane leakage. Even something as simple as a shutting off a valve in a compressor station often leads to some venting of methane.”


Traditional monitors and controls are not set up to accurately measure methane. But owners and operators can expect stricter methane reporting such as on the amount of fuel that comes into a facility, how much was combusted, and how much methane leakage has been collected for reuse. ■


HOW THE INDUSTRY IS DEALING WITH NEW METHANE REQUIREMENTS

METHANE CAPTURE

Conventional wisdom held that President Biden’s plan to decarbonize the U.S. Power industry was wounded critically, if not fatally, by the one-two punch of the U.S. Supreme Court’s Clean Air Act ruling in West Virginia v. EPA and U.S. Senator Joe Manchin’s (D-W.Va.) resistance to supporting Biden’s plan to fight climate change.


But Manchin reversed course and agreed to support a slimmed-down piece of legislation, the Inflation Reduction Act of 2022, that would direct an estimated $369 billion to renewable energy and climate-change measures. That law broadened and extended the federal government’s intervention in the power industry that stemmed from the 2021 Infrastructure Investment and Jobs Act (IIJA), which directed tens of billions of dollars into various aspects of electric power generation and grid reliability and resilience. But the U.S. power business appears to be headed for cleaner and greener pastures, according to new-build power plant data tracked by Industrial Info Resources (IIR).


Whether the U.S. generating fleet is cleaning and greening fast enough to make a dent in global climate change is the question. The Paris Agreement of 2015 pledged to take action to limit global temperature gain to either 1.5°Celsius or 2°C above pre-industrial times. The globe is nearly there, with cumulative temperature gain of approximately 1.2° C through 2022.
As the U.S. emerged from COVID-19 restrictions in 2021 and the government distributed trillions of dollars of aid, consumers engaged in “vengeance spending,” scooping up cars, taking vacations, and renovating homes.


The reckoning started in late 2021 and mounted in 2022 as prices rose for all goods and services — including energy. Gradually, the U.S. public became familiar with supply chain bottlenecks. Across the U.S. economy, inflation rose to a four-decade high, scrambling the energy sector. For the power generation industry, the wait list for new transformers stretched as long as three years.


As natural gas prices shot up, coal made some opportunistic market-share gains among operating power plants. But the sharp price increase of fossil fuels is expected to cause U.S. electric demand growth to revert to the mean of between 0% and 1% in 2022 and 2023, according to a global electricity report from International Energy Agency (IEA).


There is, however, no evidence that gas vs. coal jockeying for market share among operating power plants has had any bearing on the power industry’s new-build rush to renewables.


Figure 1: Annual carbon emissions from coal-fired power plants.


In 2014, when then-President Barack Obama first proposed his Clean Power Plan to reduce carbon emissions from coal-fired power plants by an estimated 870 million metric tons by 2030 compared with a 2005 baseline. The rule was finalized in 2015, but was never implemented because the U.S. Supreme Court, in a highly unusual step, blocked it. Years of litigation followed. The Clean Power Plan was the most litigated rulemaking that never went into effect in U.S. history.


While litigants wrestled, the market moved. For more than a decade, electric utilities, perhaps seeing the writing on the wall but certainly driven by the Clean Air Mercury Rule of 2005 and the Mercury and Air Toxics Standards rule finalized by the EPA in 2012, began closing coal-fired generators or switching them to burn natural gas instead. Federal activity on carbon regulation was also backstopped by state public utility commissions, which compelled utilities to file integrated resource plans (IRPs) on their proposed long-term electric generation options. Increasingly, those IRPs focused on decarbonization as well as low-cost options. As renewable energy became more competitive with traditional fossil-fueled generation, regulators pressed utilities to switch to the cleaner generation.


Long before the Supreme Court handed down its decision in West Virginia v. EPA, the market accomplished what lawmakers and regulators could not: meaningfully reducing CO2 emissions from coal-fired power plants. Between 2005 and 2020, according to the U.S. Energy Information Administration (EIA), CO2 emissions from coal-fired power plants dropped by about 1.2 billion metric tons — far exceeding the aims of the Obama Clean Power Plan (Figure 1).


As a demonstration of how far and fast the market has moved, renewable energy is now expected to account for about 94% of all new-build power plant construction over the 2023-2027 period. That is up from 88% of all new-build project kick-offs only a year ago. Five years ago, renewable energy was expected to account for about 56% of all new-build power plant activity over the 2018-2022 period.


For the 2023-2027 period, the rush to renewables is generalized across the U.S., but is particularly pronounced in New England, where renewables are scheduled to account for 100% of planned power plant construction, the Midwest (98%), the West Coast and Rocky Mountains (both 96%), and the Northeast (92%) (see map).


Overall, developers have scheduled the construction of about 405 GW of new generation over the next five years. That is up about 28% from a year ago, and nearly double the planned capacity additions from two years ago (Figure 2).

Not all of that new generating capacity will be built as scheduled over the next five years. Depending on the technologies involved and developers’ ability to secure financing, lock down offtake arrangements, and achieve regulatory support, we typically see between one-quarter and one-half of all announced projects delayed or cancelled. Higher interest rates mean that fewer projects will pencil out. But then again, as we have seen over the last 30 years, new power projects are announced on a near-daily basis.


Bottom line: Renewable power developers are in the green, and carbon-based developers are singing the blues.


Figure 2: Planned new-build capacity additions increase sharply.

Figure 3: Coal burn by U.S. electric generators.


IIR is not aware of any new-build coal-fired power project that is scheduled to begin construction between 2023 and 2027. This continues a long downward trend for new-build coal as well as in the number of coal miners and overall coal use by the power sector. Coal burned by U.S. electricity generators is expected to fall slightly in 2022, to about 482 million metric tons, and a further decline for 2023 is forecast by EIA (Fig. 3). Employment in coal mines held steady at about 38,000, as mines and their customers rationalized the demand for and supply of thermal coal (Fig. 4).

Figure 4: Coal mining employment continues to drop.

The IRA and IIJA laws provide some federal dollars for carbon capture and sequestration (CCS), which could help existing coal-fired power plants stay open. But we think those credits, on their own, will not be enough to help make any proposed new-build coal plants move forward. Over the next five years, most of the project spending that will take place among coal-fired power generators is expected to be for: dismantlement & demolition (D&D); environmental remediation, such as closure and cleanup of coal ash ponds; and in-plant capital spending on maintenance and upgrades.


We estimate that about $2.85 billion will be spent on D&D activities at U.S. coal plants over the 2023-2027 period. An additional $4.4 billion is scheduled to be spent on environmental remediation over that time. A third category of coal plant project spending, in-plant capital spending, covering boiler revamps, fuel switching, generator rewinds and turbine refurbishments, will reach about $820 million over the next five years. And $600 million is expected to be invested in planned maintenance at coal-fired generators over the next 2023-2027 period.


Although Coal Country welcomed the Supreme Court decision in West Virginia v. EPA, and cheered Joe Manchin’s months-long resistance to the president’s climate legislation, there was scant possibility that either would reinvigorate coal-fired generation or lead to the construction of new coal-fired generation. Mid-summer analyses from Morgan Stanley and Glenrock Associated were even bleaker: the Supreme Court decision in West Virginia would not create an opportunity to extend the lives of existing coal-fired generators, much less build new plants, analysts said. The court decision may be a setback for the Biden administration, “but utilities aren’t changing their plans,” according to Paul Patterson, an equity analyst with Glenrock Associates. He added that most of the action on reducing greenhouse gas emissions (GHGs) from the power sector has been driven by state policies, federal tax incentives, and corporate green power purchasing decisions. In the absence of federal action, there were plenty of other drivers pushing coal to the margins.

Once a coal plant is deactivated and mothballed, it’s not economic to reverse course and bring it back online. Approximately 115 GW of U.S. coal-fired generation was closed between 2011 and 2021. Going forward, we expect another 44 GW of coal-fired generation to be closed by 2025 (Fig. 5).

Numerous asset owners announced the closure of coal-fired power plants in 2022 or moved up the closure dates. During the year, the PJM Interconnection deactivated about 3.2 GW of coal-fired generation, most of which was owned by Energy Harbor. AES announced plans to exit coal by 2025. Duke told investors it would be coal-free by 2035. Xcel Energy plans to stop using coal by 2032. Public Service Company of New Mexico announced plans to close two units of its San Juan complex in September. There were many other announcements along these lines.


Another driver working against new-build coal generation is the rise of Environmental, Social and Governance (ESG) investing. More than 3,400 institutional investors have signed the U.N. Principles for Responsible Investing (PRI), and their assets under management (AUM) exceeded $121 trillion as of March 30, 2021 (Fig. 6). That means developers seeking to build new coal-fired generation have fewer places to source their capital.

Figure 6: ESG investing continues to grow.

In a cruel irony, it may be that the most valuable assets owned by retired or retiring coal-fired power plants are their transmission lines and their land. Numerous coal-fired plant sites — including those in Illinois, Colorado, Nevada, New Mexico, North Dakota, Nebraska, Minnesota and Maryland — are slated to be transformed into renewable energy and/or battery energy storage projects in the next few years, according to an investigation by The New York Times. In addition, two retired coal-fired power plants in Massachusetts and New Jersey are scheduled to be converted to receive power generated by offshore wind farms. Further out, Bill Gates-backed TerraPower has plans to build a small nuclear power plant on the grounds of a Wyoming coal-fired power plant that is scheduled to be closed in the late 2020s.


The outlook for new-build natural gas generation in the U.S. has dimmed considerably in recent years. Looking forward to the 2023-2027 period, that erosion is expected to continue. Over the next five years, new-build natural gas generators are scheduled to account for only 5% of all new powerplants scheduled to be built. Last year, that percentage was about 11%, and five years ago it stood at about 41% (Fig. 7).

Figure 7: Proposed New-Build Generation, Renewables vs. Gas


What happened? One view is that gas became a victim of the “Carbon is Public Enemy #1” campaign undertaken by environmental organizations. A more nuanced perspective is that the hands of regulators have been tied by state laws and goals on renewable portfolio standards (RPS) and GHG reduction. Gas has a bleak future in states that are driving down their GHGs while increasing their RPSs.


On a percentage basis, the Mid-Atlantic region has the highest share of proposed new-build gas generators in the U.S., accounting for about 14% of all new power plants scheduled to be built over the 2023-2027 period. Following the Mid-Atlantic are the Great Lakes (12%), the Northeast (8%) and Southwest (7%). In terms of raw numbers, the Southwest has scheduled construction of the greatest amount of new-build gas-fired generation, at 5,456 MW, followed by the Great Lakes (5,376 MW) and the Mid-Atlantic (3,033 MW) regions.
Over two dozen proposed gas-fired generators that were scheduled to be built over the next five years have been cancelled. The aggregate value of those proposed projects exceeds $13 billion. The states with the largest number of project cancellations on a project-dollar basis are: Virginia ($1.8 billion); Texas, Pennsylvania and New Jersey ($1 billion each); and Florida, California and West Virginia (all slightly less than $1 billion each).


An additional 41 new-build gas-fired generation projects with aggregate value of $15.8 billion were scheduled to begin construction over the next five years but have been delayed. Texas is far and away the state with the largest dollar-value of project delays, at more than $8 billion, followed by Michigan ($2 billion) and Ohio ($1 billion). COVID-19 has been the cause of some of those project delays. The pandemic caused labor and materials shortfalls that have affected the entire power industry. Some of these delayed gas power projects could become reactivated over the next five years.


Organized wholesale regions like ERCOT (Electric Reliability Council of Texas) and MISO (Mid-Continent Independent System Operator) have sounded alarms of a potential generation shortfall in recent years, and the heat dome of Summer 2022 stretched those regions to the limit. Electric emergencies or rolling blackouts could focus the minds of regulators on the need for more dispatchable capacity. This bears watching, as events could cause regulators to relent and permit some new gas power development.


It is too soon to declare new-build gas plants a dead artifact of the 20th century. The thousands of MW of renewable energy that are operating, under construction or scheduled to be built will need to be backed up. That challenge outstrips the current capabilities of battery energy storage systems, even leaving aside the technological challenges of lithium ion battery systems, as well as concerns over the available supply of lithium. Pumped storage hydro facilities could be paired with intermittent generation, but the cost and timeline for building new pumped-storage facilities is daunting. In short, as much as policymakers and developers want to quickly move toward higher reliance on non-emitting generation, we see a continued need for new-build gas-fired generation.

In addition to new-build generation, IIR is tracking more than $13 billion in planned in-plant capital spending at U.S. gas plants over the next five years. Also, developers, engineers, and analysts are investigating the potential to co-fire gas plants with hydrogen.


Figure 8: A more granular view of renewables.


Even before Senator Manchin reversed course over the summer and supported the president’s slimmed down climate-change bill, plans to build renewable energy generating capacity over the next five years were exploding. They have risen to about 379 GW or 94% of all planned new-build capacity over the next five years. Last year, renewables were scheduled to account for 88% of all new-build construction over the 2022-2026 period. Five years ago, for the 2018-2022 period, that percentage was 55%.


In assessing the new-build generation market, we did not include renewable energy plants that could get built due to the Inflation Reduction Act of 2022, as the thinner version of “Build Back Better” was tabbed. That proposal, with an estimated $369 billion in clean electricity funding, includes Production Tax Credits (PTCs) for wind, solar and battery energy storage, among other things. The PTC for solar power would be new, as that industry has depended on Investment Tax Credits (ITCs) for years. If anything, our estimate for the new-build renewable generation market for the next five years could be conservative.


On a percentage basis, the U.S. regions with the greenest hues are: New England (where 100% of new-build generation is expected to be renewable); Rocky Mountains and West Coast (each 96%). On a MW-basis, the regions leading the green power parade are: Rocky Mountains (133 GW), Southwest (78 GW), Great Lakes (39 GW), and West Coast (36 GW). Again, we don’t expect all this planned renewable generation to be built as proposed. But the 2023-2027 period is starting off with an enormous number of renewable energy projects.


“Other” renewable energy projects, such as hydropower and geothermal, are expected to account for as much as 49 GW, or about 12% of all renewable capacity scheduled to be built over the next five years. Hydropower, in particular, is expected to benefit from some $754 million in incentives contained in the Infrastructure Investment and Jobs Act, signed into law in late 2021 by President Biden. New-build hydro could also benefit from the Inflation Reduction Act of 2022, depending on how the enabling legislation is written: Will hydro be defined as a “renewable” source of energy? Given that people define “renewable energy” differently, we thought it would be helpful to provide a more granular look at how plans to build renewable energy break down.


The “run to the sun” has accelerated in recent years. In a category once dominated by wind power, plans to build solar generation have taken a decisive lead, with 49% of planned renewable new-build capacity, or about 184 GW, set to begin construction over the next five years (Fig. 8). Areas with the greatest amount of planned solar generation construction include the Rocky Mountains (55 GW), Southwest (52 GW), Great Lakes (26 GW) and West Coast (13 GW). A huge countervailing factor that could limit the growth in new-build solar is the rise in prices that started to become evident in 2021. The supply-chain bottlenecks and soaring costs for materials have derailed or delayed some of these planned solar projects.


Among renewable projects, wind power has long been the hare to the solar industry’s tortoise. But for the next five years, wind power will fall into second place with about 22% of all new-build generation, or about 82 GW. The U.S. regions with the greatest amount of wind power project activity over the 2023-2027 period, measured on a GW basis, include the Rocky Mountains (about 23 GW), Midwest (17 GW), Southwest (10 GW), and New England and Great Lakes (9 GW each).

Figure 9: BESS operating capacity shoots up.

Figure 10: Actual and planned BESS capacity.


Plans to build battery energy storage systems (BESS) have skyrocketed in recent years. Developers have announced plans to build as much as 64 GW of BESS over the next five years. Data from the EIA shows that developers proposed to sharply increase large-scale BESS projects between 2022 and 2024. Operational BESS capacity more than tripled in 2021, to 4.6 GW from 1.4 GW in 2020, according to the EIA (Fig 9). Most of that capacity was being deployed by regional transmission organizations (RTOs). Going forward, construction of new BESS capacity is expected to surge. The EIA projects BESS capacity will shoot up from an estimated 4.6 GW in 2021 to about 22 GW by 2025 (Fig. 10). About 382 BESS projects are scheduled to be built over the next five years, valued collectively at about $81.1 billion. The regions with the greatest amount of BESS construction activity are the: Rocky Mountains, with 76 projects valued at $33.3 billion; Southwest, with 109 projects valued at $23 billion; and West Coast, with 76 projects valued at $12 billion.


The first iteration of the nuclear renaissance looks like it will be ending with a whimper, not a bang: the last new-build nuclear power project, the two-unit addition to the Alvin W. Vogtle Nuclear Power Station, is scheduled to finish construction in 2023. Years late and billions of dollars over budget, the Vogtle unit additions, totaling 2,234 MW, were expected to be the showcase of a revived nuclear industry when they were announced in 2008.


The two new units now have an estimated $32 billion price tag, nearly three times the original cost of $12 billion. If the units are brought online in 2023, it will be roughly seven years after the first unit was scheduled to begin commercial operations. The owners, led by project manager Georgia Power Company, are embroiled in litigation over who pays what for the project. And GPC can expect some tough questioning from the Georgia Public Service Commission when prudency hearings begin.

CAN ANYTHING REVERSE THE RUSH TO RENEWABLES?

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