New coal plants in Alaska and West Virginia will receive federal support under the program. A shuttered coal plant in Maryland is also slated for restart. The remaining awards, totaling up to $425 million across the 12 modernization projects, are intended to extend operational life, improve dispatch flexibility and support baseload capacity at plants that utilities and cooperatives have been weighing for retirement.

An additional $75 million goes to the West Gateway Terminal Project in Oakland, a rail-served marine export terminal the DOE says would handle more than 10 million tons of bulk commodities annually and expand coal export access to Japan, South Korea, Taiwan, Vietnam and Malaysia.

The funding would help build new coal units in Alaska and West Virginia. The money would also help restart a shuttered coal-fired power plant in Maryland. The Department of Energy (DOE) said the selected projects are intended to strengthen domestic coal mining value chains, support baseload power generation, and enhance the resilience of critical energy infrastructure.

“To ensure our national security, the United States will continue to support our coal fleet and domestic supply chains,” Energy Secretary Chris Wright said in a statement announcing the selections.

A coal comeback?

This move is the latest in a series of efforts by the Trump administration to attempt to reverse the decline of the nation’s coal industry.

Last fall, Trump administration said it would open 13 million acres of federal lands for coal mining and provide $625 million to recommission or modernize coal-fired power plants. Under Trump’s orders, the Energy Department has required fossil-fueled power plants to keep operating past their retirement dates to meet rising U.S. power demand amid growth in data centers, artificial intelligence and electric cars. 

Trump also has directed federal agencies to identify coal resources on federal lands, lift barriers to coal mining and prioritize coal leasing on U.S. lands. A sweeping tax bill approved by Republicans and signed by Trump reduces royalty rates for coal mining from 12.5% to 7%, a significant decrease that officials said will help ensure U.S. coal producers can compete in global markets.

Coal supplied roughly 15% of U.S. electricity generation in 2024, down from about 45% in 2010. Natural gas now accounts for approximately 43%, with nuclear and renewables making up the remainder. Energy analysts have broadly characterized the administration’s coal support efforts as capable of slowing but not reversing that trajectory, given natural gas’s structural cost advantage and durable utility demand for wind and solar regardless of federal policy.

U.S. coal exports dropped during the first year of Trump’s second term, largely due to less coal being shipped to China after it imposed reciprocal tariffs on American products last year in response to broad tariffs announced by Trump, according to the Energy Information Administration. Global coal demand rose to record levels in recent years but is expected to flatten or decline in the coming years, according to the International Energy Agency.

Where’s the money going?

Reliable, Economical, and Local Advancement in Modernized Coal (RECLAIM-C)

Alliant Energy Corporation (Columbia County, Wisconsin) is undertaking a modernization at its Columbia Energy Center, a coal-fired plant in the Town of Pacific, Wisconsin. This initiative is intended to maintain baseload service and enhance the efficiency and environmental performance of the existing units. 

DOE Funding: $19,000,000
Non-DOE Funding: $29,500,000
Total Value: $48,500,000

AEPCO ST3 Modernization Project

Arizona Electric Power Cooperative, Inc. (Cochise, Arizona) is undertaking a modernization and resiliency program at the Apache Generating Station near Cochise, Arizona. The modernization efforts are expected to help increase efficiency, retain and increase dispatchable baseload capacity, and extend the operational lifespan.

DOE Funding: $20,826,000
Non-DOE Funding: $32,574,000
Total Value: $53,400,000

Antelope Valley Station Coal Modernization Opportunity

Basin Electric Power Cooperative (Mercer County, North Dakota) has proposed modernization of two coal-fired units at the Antelope Valley Station in Mercer County, North Dakota. Upgrades are meant to mitigate unplanned outages, improve efficiency, and increase generation capacity.

DOE Funding: $27,441,000
Non-DOE Funding: $42,559,000
Total Value: $70,000,000

East Bend Coal Reliability Assurance Initiative

Duke Energy Kentucky (Boone County, Kentucky) is undertaking upgrades at the coal-fired East Bend Station in Boone County, Kentucky. Upgrades are intended to improve the plant’s operational flexibility, enhance overall efficiency, and boost generation capacity.

DOE Funding: $33,400,000
Non-DOE Funding: $50,043,088
Total Value: $83,443,088

Roxboro 2 & 3 Coal Reliability Assurance Initiative

Duke Energy Progress (Person County, North Carolina) will modernize and enhance the operational capabilities at the Roxboro Plant, a coal-fired facility in Person County, North Carolina. This effort encompasses a multitude of individual projects across critical plant areas that will systematically replace and upgrade equipment meant to mitigate the occurrence of emergent failures, reduce downtime, and improve operational efficiency and dependable energy production of the plant.

DOE Funding: $28,400,000
Non-DOE Funding: $44,273,513
Total Value: $72,673,513

EKPC DOE Coal Recommissioning and Modernization

East Kentucky Power Cooperative, Inc. (Maysville, Kentucky and Pulaski, Kentucky) plans to modernize coal-fired units at the H.L. Spurlock Generating Station and John Sherman Cooper Station. Each unit will undergo upgrades that can extend operational life, improve dispatch flexibility, and ensure grid stability.

DOE Funding: $90,600,000
Non-DOE Funding: $271,800,000
Total Value: $362,400,000

M.O.R.E. Oklahoma (Modernizing Oklahoma’s Rural Energy) 

Grand River Dam Authority (Chouteau, Oklahoma) will modernize its coal-fired unit located at the Grand River Energy Center in Chouteau, Oklahoma. This modernization will extend the asset operational life and enhance capacity and enable grid stability.

DOE Funding: $28,518,000
Non-DOE Funding: $48,061,000
Total Value: $76,579,000

Modernizing the Merom Coal-Fired Power Station: Effluent Limitation Guideline Modernization Project

Hallador Power Company, LLC (Merom, Indiana) is planning to modernize its Merom Coal-Fired Power Station. This modernization initiative is meant to maintain operational reliability and “promote environmental stewardship.”

DOE Funding: $27,200,000
Non-DOE Funding: $42,491,006
Total Value: $69,691,006

Sooner DCS Modernization Project

Oklahoma Gas and Electric Company (Red Rock, Oklahoma) is undertaking a project at the Sooner Power Station near Red Rock, Oklahoma, to modernize the Distributed Control System (DCS). Upgrades to the DCS and associated field devices are meant to maintain system reliability and enhance operational efficiency.

DOE Funding: $22,513,000
Non-DOE Funding: $35,212,674
Total Value: $57,725,674

Flint Creek Coal Plant Modernization and Resiliency Program

Southwest Electric Power Company (Gentry, Arkansas) is undertaking a modernization and resiliency program at its Flint Creek Coal Plant in Gentry, Arkansas. This project involves upgrades that the company says will reduce fuel requirements, improve the plant’s operational efficiency, reliability, and overall power generation capacity, and extend the life of the asset.

DOE Funding: $29,814,400
Non-DOE Funding: $44,721,600
Total Value: $74,536,000

Tennessee Valley Authority Coal Revitalization Initiative

Tennessee Valley Authority (Stewart County, Tennessee) is beginning a coal revitalization initiative at its Cumberland Fossil Plant in Stewart County, Tennessee. This project aims to restore reliability, enhance efficiency, and extend the operational life of the coal-fired assets to meet regional demand for dispatchable power.

DOE Funding: $46,287,600
Non-DOE Funding: $69,431,400
Total Value: $115,719,000

Mitchell Mechanical Draft Cooling Tower Modernization Project

Wheeling Power Company (Moundsville, West Virginia) plans to modernize the Mitchell Plant in Moundsville, West Virginia.

DOE Funding: $51,000,000
Non-DOE Funding: $107,600,000
Total Value: $158,600,000

West Gateway Terminal Project

The West Gateway Project, spearheaded by Oakland Bulk and Oversized Terminal (OBOT) LLC, is a strategically located bulk commodities export terminal in Oakland, California. It offers direct access to the Pacific Ocean and Indo-Pacific markets, forming a part of a broader, multi-decade initiative to revitalize and reindustrialize the Oakland Army Base (OAB) property within the Port of Oakland, which was decommissioned in the late 1990s. OBOT LLC holds exclusive development rights for the property through an established ground lease with the City of Oakland.

DOE Funding: $75,000,000
Non-DOE Funding: $156,773,000
Total Value: $231,773,000

This article contains reporting from the Associated Press.

Stakeholders of IBRs with an aggregate capacity of 20 MVA or more (roughly 16 MW to 20 MW) connected at 60 kV or higher are now required to register as a Generator Owner (GO) and/or Generator Operator (GOP) under NERC Category 2. Developed in response to a 2022 Federal Energy Regulatory Commission (FERC) order, the initiative aims to improve visibility and oversight of previously unregistered facilities, providing a stronger foundation for planning, operations, and risk management. 

For stakeholders unsure whether their assets are in scope — or know they are behind — the question is no longer whether to prepare, but how to close gaps quickly, defensibly, and without disrupting operations. Radian Generation, a global provider of comprehensive services and products designed to support the complete lifecycle of renewable energy facilities, recently shared its expertise on the topic in a live web event on Factor This. Register to watch it for free on demand.

The Cause for Compliance

Based on Energy Information Administration (EIA) data, 874 existing or operating IBR sites with a total capacity of 20 MW or higher, connected at 60 kV, are on the hook for compliance with NERC, plus another 156 projects in development. Many weren’t designed with NERC in mind.

That means Radian Generation has been busy lately. According to Desmond Adams, director of implementation and GOP services, making the grid more reliable and resilient means accounting for these smaller assets.

“There are a lot of facilities that were built out there, we’ll say in the past 10 to 15 years, where it made sense to build it in that smaller size because, at that time, they didn’t have to pay for NERC compliance and ensure that these assets had all of the different things that larger sites have,” Adams explained in the Factor This web event. “In total, those assets begin to make a big impact on the grid.”

In a 2021 incident known as the Odessa Event, a grid disturbance caused numerous resources in Texas to temporarily go offline.

“This caused a huge strain on the grid when these resources that ERCOT was counting on to be available, all of a sudden, just weren’t there,” Adams recalled.

To put it bluntly, the grid wasn’t happy- an outcome NERC and its six Regional Entities are hoping to avoid moving forward.

Putting a Plan Together

For owners and operators of IBRs who aren’t sure of their NERC compliance status, Radian Generation can help with the integral starting step of developing 30-, 60-, and 90-day plans.

“Conform scope, roles, asset lists, deadlines, and immediate gaps in the first 30 days,” suggested Adib Abdulzai, vice president of operational technology and security. “In 60 days, build a compliance plan, assign owners, collect evidence, and fix obvious control gaps. And then the last 30 days, that 90 days, test the process, review its quality, clean up vendors, operators, responsibility, and prepare for audit.”

It might sound simple, but for many, the process is far from it. Ultimately, it’s the stakeholders’ willingness to invest effort in the process that determines their success.

“Folks who aren’t successful with it are the ones who don’t give it the time and attention that it deserves,” shared Adams. “Ultimately, it has to have buy-in from the owners of the assets and the leadership at those companies. The most successful companies we work with, the VPs and even the CEOs, are calling us and asking: How do we get this done? What do you need from me?”

That sort of hands-on attention to detail is essential during periods of change, such as the one affecting IBR stakeholders right now. During the web event, Adams recounted a recent conversation with a client representing a 30-megawatt wind power project. Its owners didn’t think it was subject to Category 2 compliance, but it was, in fact, a Category 1 site.

“That’s not the only facility like that,” he added.

The Stakes

Although potential fines for non-compliance can be steep, a bit of good news is that NERC and its affiliates prefer to work with generators rather than penalize them, and heavy penalties are reserved for only the most egregious offenders. Plus, one cannot be held responsible for retroactive fines.

“It’s up to NERC or the Regional Entities to identify these sites and inform them of their obligation to register,” explained Adams. “So you can only be held responsible from the point that you register.”

The tricky part is that there needs to be compliance from that point onward, and it isn’t really a ‘set-it-and-forget-it’ kind of thing.

Kellie Macpherson, Radian Generation’s executive vice president of compliance and security, adds there’s a cybersecurity element to this conversation, too. IBRs can be weak points where the grid is exposed to external threats.

To learn more, register and watch the on-demand web event on Factor This.

Additional takeaways include:

• How operators can reduce uncertainty and adopt a more defensible, sustainable compliance program
• Assessing whether solar, wind, storage, or hybrid assets may be in scope for NERC Category 2 requirements
• What leadership should know about post-deadline risk
• Understanding what the Category 2 readiness process looks like from a real-world customer perspective
• What stakeholders should do if they think they are in scope but are not registered
• Which documentation matters most
• How to prioritize gaps when considering multiple assets

With the waiver in place, Constellation will now be able to transfer some grid rights from its Eddystone natural gas plant to the 835-megawatt nuclear plant, avoiding interconnection delays caused by stalled transmission projects.

Three Mile Island, which will be restarted under the new name of Crane Clean Energy Center, was shut down in 2019. The previous owner Exelon decided to end operations after a financial rescue package did not come from Pennsylvania legislators.

Constellation said that during the system impact study for the plant’s restart, PJM identified numerous transmission projects that would include hundreds of miles of new lines as contingent facilities. However, Constellation argued that many of these lines have already incurred years of delays, and if those new lines are still included as contingent facilities in the plant’s final interconnection agreement, the plant’s restart would be held up until every contingent facility is completed. The company said this could cause Crane to sit in limbo for at least three years, ready to generate, but not permitted to do so.

Constellation told FERC that, based on its analysis of Crane’s Phase I System Impact Study Report, it has determined that transferring the Eddystone Units’ CIRs to Crane would enable Constellation to expedite Crane’s full deliverability and “improve its position for interim deliverability” in the meantime.

A new life for Three Mile Island

The reactor at Three Mile Island had been out of operation for five years when Constellation Energy announced in 2024 that it would spend $1.6 billion to restart it under a 20-year agreement with Microsoft to buy the power for its data centers. In late 2025, the U.S. Department of Energy said it would loan $1 billion to help finance the restart of the plant. The loan was issued under an existing $250 billion energy infrastructure program initially authorized by Congress in 2022.

The plant, on an island in the Susquehanna River just outside Harrisburg, was the site of the nation’s worst commercial nuclear power accident, in 1979. The accident destroyed one reactor, Unit 2, and left the plant with one functioning reactor, Unit 1. In 2019, Constellation Energy’s then-parent company Exelon shut down the functioning reactor, saying it was losing money and Pennsylvania lawmakers had refused to subsidize it to keep it running.

According to a recent statewide poll, conducted by Susquehanna Polling & Research and cited by Constellation, Pennsylvanians favor restarting the plant by a more than 2-1 margin. The same independent poll found that 70% of state residents support the continued use of nuclear energy as a source of carbon-free energy.

Constellation purchased TMI Unit 1, in 1999. Before it was retired for economic reasons in 2019, the plant had a generating capacity of 837 MW. In its last year of operation, the plant was producing electricity at maximum capacity 96.3% of the time. The plant had an annual payroll of about $60 million and employed more than 600 full-time workers, in addition to the roughly 1,000 craftspeople that supported the plant’s biennial refueling outages.

This article contains reporting from the Associated Press.

The acquisition would add approximately 2.6 GW of natural gas generation capacity to Talen’s portfolio. Talen said the acquisition will “substantially expand” its presence in the western PJM market and add additional efficient baseload generation assets to its fleet. The acquisition price is $3.45 billion and consists of approximately $2.55 billion in cash and approximately $900 million in Talen stock. 

The 1,218-MW Lawrenceburg and 869-MW Waterford facilities have an average heat rate of approximately 7,000 Btu/kWh and capacity factors greater than 80%. The 480-megawatt Darby facility also operates as a peaking unit. Talen argues that the addition of the facilities to its portfolio enhances the company’s ability to offer low-carbon capacity to hyperscale data centers and large commercial off-takers.

Talen received clearance from the Federal Energy Regulatory Commission (FERC) this week and from the Indiana Utility Regulatory Commission on May 27. The waiting period pursuant to the Hart-Scott-Rodino Act of 1976 expired in March 2026.

“I am pleased to announce that we have received the key regulatory clearances necessary to close on Talen’s highly accretive acquisition of the Lawrenceburg, Waterford and Darby plants,” said Talen President Terry Nutt. “We look forward to completing this transaction and adding these assets to our portfolio.”

The acquisition remains subject to customary closing conditions, which Talen expects to be “promptly satisfied,” and is anticipated to close in the coming weeks.

Preparing an accurate water balance (WB) is important for any steam-generating power plant. At existing facilities, updated WBs (and piping blueprints) with all lines clearly shown helps plant personnel monitor equipment performance and track down leaks that may be caused by malfunctioning equipment/control systems or problems in piping networks. (I know from experience that updated prints can save a plant from crisis situations.) For plants in the design phase, a preliminary WB is critical for calculating the size of the makeup water treatment system and wastewater discharge volumes. This series includes several personal case histories to provide real-world examples.

Starting with a modern example

The phase-out of coal-fired power plants (currently postponed to some degree) over the last three decades accelerated selection of combustion turbine generators (CTG), including many combined cycle plants. This trend seems destined to continue, in large part to provide power for planned data centers.¹ Accordingly, we will use the fundamental heat recovery steam generator (HRSG) fluid flow schematic shown below as a foundation for reviewing modern water balance topics.

Let us first consider the important concept of control volumes.

Control volume basics

A standard method to analyze overall mass and energy balances of a system is to draw a control volume around the system. The dashed purple line in Figure 1 highlights the control volume for water flow. As can be seen, the input is the plant makeup stream, which, of course, is a function of the needs of the plant. The overall makeup requirement can be calculated from the control volume discharge streams. In clockwise order from the top left, these are:

• Combustion turbine evaporative cooler evaporation
• HRSG blowdown flash steam
• Wastewater to the wastewater treatment plant (WWTP)
• Cooling tower evaporation
• Cooling tower blowdown

We will consider these streams first, but within the control volume are internal streams in which flow monitoring can help to determine if equipment is performing properly and if there are leaks in distribution piping. These include:

• Permeate and reject flows from the pretreatment ultrafiltration (UF) system ahead of the RO unit
• Permeate and reject flows from the reverse osmosis (RO) unit. A well-designed RO system will be equipped with flow meters and other instrumentation, with a computer program that “normalizes” data to account for flow changes due to seasonal temperature fluctuations. These changes can mask membrane fouling or scale formation.
• Condensate transfer back and forth from the HRSG condenser hotwell and the condensate tank, per changes in load
• Condensate makeup to closed cooling water systems
• (Note the dashed line “Water for CTG NOx Control.” This is a special case that will be addressed later.)

We will discuss these processes in Part 2.

Representative flow rates

Sophisticated computer programs are available to calculate energy and materials balances during the plant design phase. Per one of the most widely used programs, listed below are the projected water and steam flows for a 1×1 combustion turbine-HRSG arrangement for a power plant in the eastern U.S., on a very warm (but not intensely hot) summer day.

These calculations are for a triple-pressure, feed-forward low-pressure (FFLP) HRSG, which is the most common configuration for combined cycle heat recovery steam generators. A general schematic is shown in Appendix A. I included the steam flows from the three evaporators in Figure 2, as this provides a good illustration of how the flows are divided between the three steam generators, aka, evaporators.

We will apply this data to the schematic shown in Figure 1, starting with a control-volume water accounting.

This total is the required makeup for this case. Of course, flows will change with varying conditions. Note the various storage/break tanks in the flow diagram. These vessels buffer water flow and keep equipment from having to cycle up and down constantly to meet demand.

Cooling Tower Flows

With regard to the overall makeup requirement, the outstanding item is the water lost from cooling tower evaporation and blowdown, which brings up an interesting and at times contentious issue. When I started in the coal-fired power industry in 1981, my plant and many others around the country were on once-through cooling systems with the supply coming from a human-made lake or reservoir. After extracting heat, the cooling water directly discharges to the source. However, environmental regulators identified two major problems with once-through systems. First is the potential for fatal impingement and entrapment of aquatic creatures on inlet water screens. The second is increased mortality of aquatic organisms at the cooling water discharge due to the significantly higher temperature than the surrounding water body. Summer-time discharge temperatures can be especially problematic.

Consequently, regulations on once-through cooling for new plants tightened and were replaced by an emphasis on alternative cooling methods, with cooling tower-based systems being a primary choice. But this requirement introduced a different issue. Depending on ambient conditions, typically between 65% and 90% of heat transfer in a conventional cooling tower occurs from evaporation of a small fraction, perhaps 1-2% or so, of the circulating water. (Per the Figure 2 data, the loss to evaporation is (1,630/105,168) * 100 = 1.55%) Tower evaporation, combined with the calculated blowdown of 407 gpm, accounts for 2,037 gpm of the total makeup requirement of 2,410 gpm for this case. Accordingly, cooling tower makeup water requirements may sometimes become problematic regarding intake and discharge issues. I have seen design scenarios where a facility was placed between the proverbial “rock and a hard place,” in which the only method to meet an intake volume limit was to operate the cooling tower at a high “cycles of concentration (COC)”² to reduce blowdown, but where the concentration of impurities in the blowdown then would violate discharge chemistry regulations.

Plants in arid locations may have no alternative but an air-cooled condenser (ACC). A primary drawback, besides their extremely large size (among other issues), is that ACCs can only cool the condensate to an approach to the dry bulb temperature, unlike cooling towers with an approach to wet bulb.² This aspect of ACCs can result in a significant loss of plant efficiency during hot weather.

On a slightly different note, colleagues of mine and I have reviewed project specifications for cooling towers in which it appeared that the designers selected a high COC as sort of a blind choice, when in actuality the plant’s water usage and discharge regulations did not require it. What some developers do not seem to realize is that at higher COC, the blowdown savings become marginal, as shown in the following graph built around data from Figure 2.

All graphs like this are asymptotic, and beyond six COC or so the water savings from increased cycling becomes marginal. Critically, the increasing concentration of impurities at high cycles makes chemistry control difficult and more expensive.

A quick note, while the calculations for cooling tower design can be rather complicated, a straightforward set of equations is available that provide good approximations for flow in existing towers. The fundamental equation for evaporation is:

E = (ƒ * R * ΔT * c_p)/1000 Eq. 1

E = Evaporation in gallons-per-minute (gpm)
R = Recirculation rate in gpm
ΔT = Temperature difference (range) between the warm and cooled circulating water (oF)
Cp = Heat capacity of water at ambient conditions (1.0 Btu/lbm-oF)
ƒ = A correction factor that accounts for evaporative and sensible heat transfer, where the range is often considered to be 0.65 to 0.95 from cold to hot ambient temperatures. Humidity also influences the correction factor.

The factor of 1,000 is the approximate latent heat of vaporization (Btu/lbm) of water at ambient conditions.

As a check, plugging in an “ƒ” value of 0.9 for the circulating water flow rate shown in Figure 2, and with the heat rate program’s calculated ΔT of 16.6o F, produces almost the identical value of 1,630 gpm of evaporation calculated by the program.

Additional straightforward algebraic equations are available to reasonably calculate the blowdown (BD) and makeup (MU) requirements from a tower when the evaporation is known and COC has been selected.

BD = E/(COC – 1) Eq. 2
MU = E + BD + D + L Eq. 3

Where, D = drift and L = losses from leaks. These are usually minor and can be neglected for general calculations.

Combustion Turbine Evaporative Cooler

Many combustion turbines are equipped with an inlet air evaporative cooler, as this process can greatly improve compressor efficiency during warm ambient conditions. The CTG evap cooler is basically a smaller version of a cooling tower, with internal media to enhance air/water contact. As Figure 2 and Table 1 illustrate, a significant amount of water may be lost to evaporation during warm conditions.

HRSG Blowdown Tank Steam Vent

Blowdown has been a standard feature of boilers from the beginning to help control dissolved solids concentrations in the boiler water. When the blowdown stream reaches the vented tank, some of the water, whose temperature is above the atmospheric boiling point, flashes off. Under normal operation, the blowdown rate is usually small, but it can be higher at startups. During my time at two coal-fired power plants, the issue about monitoring of blowdown flow would periodically arise. However, it is not an easy task to directly measure flow of a very hot fluid stream.

Miscellaneous Plant Services

This is wastewater that comes from such things as equipment wash down water, small leakage from pump seals, and perhaps other streams that enter floor drains. As expected, the drainage can accumulate particulates, oily compounds, and other debris that may need to be removed in an on-site wastewater treatment plant before discharge. The value shown in Table 1 is purely an arbritrary value. Operating experience will reveal a range for this miscellaneous water usage.

Monitoring Major Flows

Water meters in strategic locations are important for analyzing overall water usage and identifying major problems. For example, the author once assisted, in a consulting role, power plant personnel who were searching for a major leak on the main inlet water line. The supply came from one of the utility’s potable water treatment plants, located nearby, with the line metered at the water treatment facility. Water usage suddenly increased dramatically. We employed a portable ultrasonic flowmeter to check individual circuits within the power plant, but the data showed no problems in any internal networks. A utility employee, who walked the path of the buried line from the power plant to the water plant, found saturated soil with some soil erosion at an intermediate point. The spot was close to a major river and had been previously overlooked. Excavation revealed a large leak. After repair, power plant water usage readings returned to normal.

Looking Ahead to Part 2

In the next installment, we will examine internal water balance monitoring and look at additional examples in which ultrasonic flow meters proved valuable for identifying water losses on closed cooling water circuits, condensate flow to and from steam generators, and others. Some of these examples come from my direct coal-fired plant experience. The ultimate task, from roughly a decade ago, was helping plant personnel at a large, four unit coal-fired plant revise the complete water balance, which included calculating flows to and from wet-flue gas desulfurization systems, ash ponds, and other locations via piping and channels that criss-crossed the plant.

Disclaimer

This series outlines, utilizing fundamental principles, the importance of developing and maintaining accurate water balances. Every facility is unique and requires specific evaluations. For example, Figure 1 shows various equipment discharge streams being routed to the cooling tower makeup. In some cases, some of these may require individual discharge. Also, depending upon the raw water source, pretreatment of the entire influent stream may be required before admission to the plant. Important issues in this regard will be covered in a later installment.

References

1. Clark, K., Utilities advance combined-cycle projects across Midwest and Southeast, Power Engineering, May 2026.
2. Buecker, B., “Advanced cooling water treatment concepts, Parts 1-6”; Power Engineering, November 2022 – January 2023.

About the Author: Brad Buecker currently serves as Senior Technical Consultant with SAMCO Technologies. He is also the owner of Buecker & Associates, LLC, which provides independent technical writing/marketing services. Buecker has many years of experience in or supporting the power industry, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Illinois) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kansas, station. Additionally, his background includes eleven years with two engineering firms, Burns & McDonnell and Kiewit, and two years as acting water/wastewater supervisor at a chemical plant. Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry. He has authored or co-authored over 300 articles for various technical trade magazines, and he has written three books on power plant chemistry and air pollution control. He is a member of the ACS, AIChE, AMPP, ASME, AWT, and he is active with POWERGEN, the Electric Utility & Cogeneration Chemistry Workshop (EUC²W), and the International Water Conference. He can be reached at bueckerb@samcotech.com and beakertoo@aol.com.

Nextpower said it expects the acquisition to expand its technology platform to include battery energy storage systems (BESS) and intelligent controls for critical power infrastructure. The company projects that global demand for storage outside China could represent an opportunity of up to $35 billion by 2030, with the U.S. accounting for up to $15 billion.

“Many of our customers have rapidly expanded their storage programs and asked us to extend Nextpower’s platform into power conversion and BESS to deliver fully integrated firm power solutions,” said Dan Shugar, founder and CEO of Nextpower. “Together with our recently announced and complementary power conversion acquisition, we expect that Prevalon’s BESS platform will open new market opportunities for Nextpower in AI data center power supply applications. Prevalon is already engaged with large hyperscalers with a lean, seasoned team that has a solid track record delivering BESS for utilities and IPPs across a variety of use cases.”

Prevalon’s Hybrid Power Stabilizer is designed to manage rapid load changes and support grid stability, while its HD5 DC block and newly released HD5 AC block products provide modular energy storage building blocks supported by insightOS controls, monitoring, and diagnostics.

“Prevalon shares Nextpower’s relentless focus on innovation, quality, reliability, and customer success,” said Tom Cornell, president and CEO of Prevalon Energy. “Operating as part of Nextpower, we can leverage their global reach and deep client relationships. Our customers will benefit from doing business with a reliable, investment-grade partner with decades of experience in power generation and management.”

The transaction is expected to close in Q2 FY27, subject to customary regulatory approvals and closing conditions.

In connection with the transaction, Nextpower is raising its fiscal year 2027 outlook, which assumes the successful closing of the transaction. Nextpower now expects fiscal 2027 revenue of approximately $4.0 billion to $4.4 billion, compared to its prior outlook of $3.8 billion to $4.1 billion, and adjusted EBITDA of approximately $845 million to $930 million, compared to its prior outlook of $825 million to $900 million. Nextpower will provide additional details on its updated outlook during an investor conference call later today.

In February 2024, Mitsubishi Power announced it was rebranding its BESS business into a standalone and legally separated company, Prevalon. Prevalon brought experience from the BESS business at Mitsubishi Power – over 30 projects, and three gigawatt hours (GWh) of utility-scale battery energy storage systems (BESS) deployed globally. Mitsubishi Power said Prevalon was meant to operate “with the agility of a startup.”

Early last year, Idaho Power Company tapped Prevalon Energy to supply what is slated to be the state of Idaho’s largest battery energy storage system (BESS), a 200 MW/800 MWh project. The BESS would enhance grid resiliency as a net peak solution, helping the utility maintain reliable power during periods of high demand. It was the second storage deal between the Mitsubishi Power Americas spinout and Idaho’s largest utility, following a similar arrangement for a 328 MWh BESS announced in 2024.

In its May Short-Term Energy Outlook (STEO), the EIA notes that despite a 2% increase in overall electricity demand in the U.S. this summer, it expects natural gas-fired generation to be comparable to last summer. The EIA attributes this largely to forecasts of increased generation from renewables.

EIA projects that natural gas consumption in the U.S. electric power sector will average 43.7 billion cubic feet per day (Bcf/d) during the summer (June through September), the same as in the summer of 2025, and 4% above the five-year summer average (2021–2025). It also forecasts that natural gas consumption for power generation will increase 6% (2.4 Bcf/d) during the summer of 2027 to 46.1 Bcf/d, surpassing the previous record set in 2024 by 3%.

But what’s different about next summer? Data centers and manufacturing facilities – and a whole lot of them. The record-high natural gas consumption EIA forecasts for next summer is primarily driven by increasing sales of electricity to the commercial and industrial sectors in the West South Central and Mid-Atlantic regions. New data centers and large manufacturing facilities, mainly in Texas and Virginia, are driving up demand in ERCOT and PJM, respectively.

EIA expects commercial and industrial electricity demand in the West South Central region to increase 20% from the summer of 2025 to the summer of 2027. Besides the commercial demand, EIA attributes growing industrial demand in the region to the increase of electrification in the oil and natural gas sector, among other industrial projects. ERCOT will likely meet rising demand with more natural gas and solar generation, EIA projects, with a 22% increase in natural gas generation in ERCOT expected between 2025 and 2027.

PJM, on the other hand, has been steadily increasing its natural gas consumption for electricity for at least a decade, EIA said, with the region experiencing increased power demand and as natural gas generation becomes more competitive with coal. Natural gas consumption for electricity generation in PJM is forecast to increase by 6% (9 BkWh) in the summer of 2027 compared to the summer of 2025, and solar generation is forecast to increase 32% (4 BkWh) over the same period.

The U.S. electricity generation mix continues to shift away from coal, with the past decade seeing a steady shift from coal to natural gas and renewables (primarily solar). However, coal is still here to stay, as EIA recently argued that during the first four months of 2026, electricity, natural gas, and coal prices have suggested “favorable economics” for coal generation in the Midcontinent Independent System Operator (MISO) region.

Coal’s “dark spread,” or the difference between fuel costs and wholesale electricity prices, in the MISO region outpaced a similar measure for natural gas generators called the spark spread. The difference between the dark and spark spreads reached $530 per megawatt-hour (MWh) during Winter Storm Fern in January, per EIA.

A cluster of large-scale data center power projects taking shape in southeast Wyoming is drawing attention to a broader shift in the power generation industry. Midstream infrastructure companies are increasingly stepping into the role of power producers, using their existing pipeline networks to compete for data center load that the traditional grid cannot yet absorb on its own.

The latest visible example of that trend in the Mountain West is Tallgrass Energy’s Cheyenne Power Hub, a project that is now approaching equipment delivery.

Earlier this month, Tallgrass and Mitsubishi Power announced the delivery location for the first two M501JAC gas turbines to be incorporated into the hub’s first phase. The units are expected to provide approximately 1,150 megawatts (MW) of capacity, fueled by natural gas from Tallgrass’ Rockies Express Pipeline. Installation of the first turbine is expected to begin as early as July.

Representing an investment projected to exceed $7 billion, the hub is being developed within the Switchgrass Industrial Park in Laramie County. A site plan approved by county commissioners in January identified two distinct development parcels.

Project specifications

The power generation component, designated as the BFC Power and Cheyenne Power Hub Project, would include two combined cycle power plants, along with temporary and permanent aeroderivative turbines intended to provide startup, backup, and base load supplemental generation, according to site plan documents. A fuel cell yard is also listed among the major project components.

The data center the hub will serve is identified in planning documents as Project Jade, situated on an adjacent 600-acre parcel. Tallgrass announced last July that Crusoe, which describes itself as a vertically integrated AI infrastructure provider, would be its partner in developing the data center campus. The initial campus is sized at 1.8 gigawatts (GW) with the potential to scale to 10 GW.

While Tallgrass and Mitsubishi Power emphasized in a dual press release that behind-the-meter generation avoids adding strain to the existing transmission system, a grid interconnection is also included in the design to allow for future renewable integration.

The project’s proximity to Tallgrass’s Trailblazer carbon capture and sequestration hub also provides a long-term pathway for decarbonization that few competing projects can claim, the companies said.

The Tallgrass model closely parallels what Williams Companies has been building elsewhere in the U.S. As we reported last November, Williams has committed $5.1 billion to what it calls Power Innovation projects, modular gas-fired or hybrid plants targeted at data centers and industrial loads in capacity-constrained regions.

Williams CEO Chad Zamarin said at the time that the pipeline of opportunities “extends throughout the end of the decade and beyond,” and that the company had secured equipment supplier positions to stay ahead of demand.

The scale of those commitments is landing on a manufacturing base already running near capacity.

Equipment demand signals

Mitsubishi Heavy Industries reported that its Gas Turbine Combined Cycle (GTCC) segment booked orders for 35 large-frame gas turbines in its fiscal year ending March 31, 2026, a result the company said significantly exceeded its own record from the prior year.

The Americas region accounted for 19 of those orders, up from 11 the year before, driving a combined cycle order backlog that has surpassed five trillion yen, or roughly $34 billion, according to company financial filings.

MHI attributed the growth to several converging factors: the transition away from coal and oil-fired generation, the need for peaking capacity to offset renewable intermittency, and accelerating electricity demand tied to data centers.

GE Vernova, one of Mitsubishi Power’s chief competitors in the large-frame gas turbine market, is reporting similar demand dynamics.

The company signed 21 GW of new gas turbine agreements in the first quarter of 2026 alone, pushing total GW under contract from 83 to 100 sequentially and backlog from 40 to 44 GW. Slot reservation agreements climbed from 43 to 56 GW in a single quarter, as customers accelerated procurement to secure production capacity in 2030 after 2029 slots filled faster than expected.

Entering the first quarter, GE Vernova had roughly 10 GW of available capacity for 2029. It exited with approximately 10 GW remaining, spread across 2029 and 2030 combined.

Pricing reflects the tightening. New gas turbine orders in the first half of 2026 are tracking 10 to 20 percentage points higher on a dollar-per-kilowatt basis than fourth-quarter 2025 orders, Chief Executive Scott Strazik told analysts. According to consulting firm Wood Mackenzie, gas turbine prices are projected to reach $600 per kilowatt by the end of 2027, nearly triple 2019 levels.

Strazik cautioned that lead times running around three years for heavy-duty units often obscure where the real bottlenecks sit.

“In many of the cases with these projects, the gas turbines are really not the gating item when you’re talking about a 3-year cycle from when a project starts, the EPC buildout, the permitting, the fuel availability,” he said.

GE Vernova is moving to expand output, targeting 20 GW of annualized production capacity by the third quarter of 2026 and 24 GW by 2028, while adding roughly 1,800 U.S. production workers across 2025 and 2026.

The Mountain West: An emerging destination?

The Wyoming projects are taking shape in a region that has moved from the periphery of U.S. power investment discussions to somewhere closer to the center.

Electricity demand across the Western grid is projected to grow more than 20 percent this decade, driven by AI infrastructure buildout, advanced manufacturing, electrification, and population growth. Data centers alone account for an estimated 90 GW of projected demand over that period. U.S. electricity consumption is expected to reach record highs in both 2026 and 2027.

The Interior West is absorbing a disproportionate share of that growth. Utah, Arizona, Colorado, Nevada and New Mexico are among the fastest-growing electricity markets in the country, with utilities across the region forecasting demand growth exceeding 50 percent over the next decade.

In Utah specifically, the Salt Lake Valley has emerged as a hyperscale data center destination, with more than 1,200 MW of data center power capacity expected in the regional market and projected data center capacity growth of nearly 700 percent by 2030. Individual hyperscale campuses in the region require 200 MW to 1,000 MW of dedicated power, and some proposed AI facilities are being designed at a gigawatt scale.

POWERGEN 2027, scheduled for next January in Salt Lake City, will convene the utilities, developers, EPCs and equipment suppliers navigating these pressures in the region.

The consideration includes a base purchase price of $650 million, plus up to an additional $400 million of contingent consideration. The combination would form an alternative asset manager with combined assets representing more than $150 billion. Since ArcLight’s founding in 2001, ArcLight has owned, controlled, or operated over 70 GW of generation assets and 48,000 miles of electric and gas transmission and storage infrastructure, representing more than $90 billion of enterprise value.

The transaction is conditioned upon completion of the previously announced acquisition of DigitalBridge by an affiliate of SoftBank Group Corp. and will not alter or affect the terms of or consideration payable under the SoftBank Acquisition, DigitalBridge said.

“Digital infrastructure is a specialist business, and ArcLight has operated with that same philosophy in power infrastructure for more than two decades, building deep expertise across power, renewables, batteries, transmission, and midstream infrastructure,” said Marc Ganzi, Chief Executive Officer of DigitalBridge. “The shared conviction that specialization creates durable advantages is foundational to this combination and expands what we can deliver for our limited partners and customers. AI is rewiring the global power equation, accelerating investment across generation, transmission, and behind-the-meter infrastructure. We believe the firms best positioned for this next phase of growth will be those that are able to underwrite both digital and energy infrastructure with equal depth and credibility.”

ArcLight will operate as a separately managed business as part of the DigitalBridge platform. ArcLight will maintain continuity in its investment processes consistent with its long-standing commitments to limited partners, including its focus on targeting attractive risk-adjusted returns and DPI, disciplined risk management, and partnership-based approach, which will remain intact.

Upon completion of the transaction, Daniel Revers will serve as Vice Chairman of DigitalBridge; Angelo Acconcia will serve as Managing Partner of ArcLight; and Jake Erhard, currently a Partner at ArcLight, will become Senior Partner.

The transaction is subject to customary closing conditions, including required regulatory approvals, requisite limited partner consents, and the completion of the SoftBank Acquisition. The merger agreement will be filed with the SEC.

“Meeting the power demands of AI infrastructure, reshoring, and electrification is a generational opportunity. Power has become the critical bottleneck for digital infrastructure buildout, and solving it takes expertise and dedicated people,” said Angelo Acconcia, Managing Partner of ArcLight. “We’ve built 25 years of technical knowledge, regulatory relationships, and operational depth in electrification infrastructure. Over the past five years alone, we have significantly expanded our team, resources, and capabilities to create an integrated platform to meet this need at scale. ArcLight looks forward to building on this momentum in partnership with DigitalBridge as we execute on an integrated approach to powering the digital economy.”

Last month, ArcLight closed on its ArcLight Infrastructure Partners Fund VIII with $3.9 billion in total commitments. The fund was oversubscribed, exceeding the target capital commitment of $3.0 billion by 30%. ArcLight has raised more than $6B across all vehicles over the last 3 months. 

Originally published in Factor This.

The U.S. Energy Information Administration (EIA) argues that during the first four months of 2026, electricity, natural gas, and coal prices have suggested “favorable economics” for coal generation in the Midcontinent Independent System Operator (MISO) region.

Coal’s “dark spread,” or the difference between fuel costs and wholesale electricity prices, in the MISO region outpaced a similar measure for natural gas generators called the spark spread. The difference between the dark and spark spreads reached $530 per megawatt-hour (MWh) during Winter Storm Fern in January, per EIA.

This trend began in late 2024, when MISO’s dark spread began to be “consistently larger” than the spark spread, EIA said. Last year, the dark spread in MISO increased 111% compared to 2024, largely due to electricity prices increasing faster than coal generating prices. The spark spread in MISO increased at 18%, which EIA attributes to rising costs for natural gas generation offsetting increasing electricity prices.

Between 2024 and 2025, the average electricity price in MISO increased 44%, while coal prices only increased 3%. Additionally, during that period, coal’s dark spread increased from $11/MWh to $23/MWh. Natural gas prices, on the other hand, increased 63% in the same time period, while the spark spread increase was $2/MWh, increasing from $12/MWh in 2024 to $14/MWh in 2025.

EIA notes that during Winter Storm Fern, there were “large divergences” between dark and spark spreads for six straight days. MISO’s daily average power prices exceeded $260/MWh from January 26 to January 28, while electricity demand during that time was 11% lower than the same weekday period before the storm. These high prices were mostly driven by spikes in natural gas prices, partially due to heating demand created by the storm. However, coal is much less sensitive to daily fluctuations in demand, EIA said, due to lead times in delivery.

Coal’s future is now almost entirely policy-dependent, according to EIA’s 2026 outlook. With EPA’s 2024 emissions rules in place, coal generation drops below 1% by 2050 and 100 to 125 gigawatts retire. Without those rules, coal still declines but holds roughly 5% share, with retirements falling to about 70 GW. In either scenario, EIA projects 25 to 40 GW of coal plants convert to natural gas co-firing before eventual retirement by 2038.

What’s going on in ERCOT?

In Texas’ ERCOT market, utility-scale solar generation is expected to surpass coal for the first time this year, per EIA. In its latest Short-Term Energy Outlook (STEO), EIA said it expects utiltiy-scale solar generation to reach 78 billion kilowatthours (BkWh) this year, compared to 60 BkWh for coal.

Natural gas is still the top source of electricity generation in ERCOT, making up an average of 44% of the electricity generation mix from 2021 to 2025. During that same period, solar’s share of the mix has increased from 4% to 12%, while coal’s has decreased from 19% to 13%.

ERCOT is seeing so much new renewable energy added to its grid that EIA expects 40% of total solar capacity additions in the U.S. this year to occur in Texas.