The refueling will result in a carbon intensity reduction of 70% by 2030 compared to 2018 levels, AES Indiana said. The coal-to-gas conversion is expected complete by the end of 2026, which would make AES Indiana the first investor-owned utility in the state to cease burning coal.

AES Indiana says converting Petersburg Units 3 & 4 aligns with its 2022 Integrated Resource Plan (IRP). In addition to repowering, the Company’s portfolio includes adding approximately 1,300 MW of wind, solar and battery storage through competitively bid projects.

Last week, AES Indiana announced it acquired the Hoosier Wind project, a 106 MW wind farm in Benton County, Indiana. Earlier this year, AES Indiana received IURC approval for a 200 MW, 4-hour standalone battery energy storage system, the largest in the MISO region.

Petersburg Units 3 and 4 each have a nameplate capacity of 690 MW and came online in 1977 and 1986, respectively. AES Indiana retired the 230 MW Petersburg Unit 1 in May 2021 and the 415 MW Petersburg Unit 2 in June 2023.

Though coal wasn’t specifically named in a Senate bill that seeks to make Utah an “energy independent” state, the resource was front and center in one of the hottest debates during the last days of the legislative session. The aim of the bills was to keep coal plants from “prematurely” closing, sponsors said, and to not fall in the same “trap” as states like California, which are aggressively pursuing a transition to a cleaner energy grid.

The approved SB224, Energy Independence Amendments, requires the Public Service Commission to change the factors it considers when making decisions on connecting or closing energy resources. One of them is presuming that the cost of “proven” significant energy resources are reasonable. While other parties may challenge that assumption, lawmakers and advocates argue that this not only prioritizes fossil fuels, but breaks a regulatory compact that has kept energy rates low in Utah.

The bill, House sponsor Rep. Carl Albrecht, R-Richfield, said, directs the commission to assume control over the available capacity in Utah plants, as West Coast states renounce coal. 

“As the state grows, this excess capacity can be used in Utah or sold into the market to customers who need reliable, dispatchable power at very attractive rates and keep rates low in the long run for us,” Albrecht told the House on the last day of the session. 

The bill now awaiting the governor’s signature was criticized by lawmakers on both sides of the aisle who, like Rep. Joel Briscoe, D-Salt Lake City, who argued that the legislation is betting that other states mentioned in the debate, such as California, Washington and Oregon, won’t be able to meet their energy needs with cleaner resources, which are emerging in the market. 

That’s a bet that the California Energy Commission predicts won’t pay off. California is in pursuit of achieving 100% clean electricity by 2045 and its policies wouldn’t allow the state to purchase new power from coal plants, including in Utah. 

“California’s investor-owned utilities, which serve a large swath of the state, are prohibited by law from entering into contracts to purchase coal power,” the California Energy Commission said in a statement. 

Data from 2021 shows that 59% of retail electricity sales in California came from non-fossil fuel sources, such as wind, solar, hydro and nuclear power, a rise from the 41% the state had in 2013. 

Still, California, which shares some of the most prominent transmission lines with Utah coal plants, is doing its own in-house emergency planning to use fossil fuels as a backup in extreme weather, agreeing to extend operations at three natural gas plants in Southern California.

Rate increase prediction

During the bill’s House debate, lawmakers from both parties argued that large monopolies — such as utilities — don’t naturally keep rates low. However, the state has a regulating mechanism in which the Public Service Commission requires utilities to demonstrate they are choosing the least expensive mix of power that meets the state’s demand.

Before the bill passed, the burden to show that proof relied on the utility, Rep. Ray Ward, R-Bountiful said. The new policy turns that around.

“We’re just going to presume that if you’re burning coal, your costs are reasonable. Utilities won’t have to show that it is the least expensive to the ratepayers,” Ward said to the House. “And (the bill) says that that presumption can only be challenged by an outside party, who shows that those costs are unreasonable, an outside party that does not have access to the represented utility.” 

Though coal has served the state as the cheapest option for ratepayers, it’s difficult to predict whether it will remain so in the next decades, he said, and the state should be careful before walking away from a regulatory framework that works.

“People will be able to draw a straight line between those rate increases and the vote we take in this body today,” said Briscoe, who unsuccessfully tried to strike that new policy, “because this upends decades of work on the relationship between the utility and the ratepayers in Utah.” 

Rate raises are among the repercussions that the Utah Office of Consumer Service warned about in a public comment, explaining that the rule would shift risks away from the utility to customers.

“This fundamentally shifts utility regulation,” said Michele Beck, director of the office, “and it’s not going to be in a way that benefits customers, you’re going to see higher rates from this.”

Advocates from the Sierra Club added that trying to keep coal plants open is “uneconomical,” as data from PacifiCorp shows that 60% of its plants are more expensive to run than to replace with other sources.

Albrecht doesn’t see how that could be the case for Utah, though. 

“Most people think that if we keep these plants, it’ll raise rates, and that’s absolutely not true,” he said, “because the baseload energy that we have, which is coal and gas, has kept our rates lower.”

Though he has been a fierce defender of coal, Albrecht doesn’t consider himself “a radical coal guy,” as he drives a hybrid car and installed solar panels on his roof. Besides helping run SB224, Albrecht sponsored other bills that could benefit cleaner energy sources, like geothermal, via tax credits. But, as of now, he said, coal and natural gas are what will keep the lights on.

Keeping coal running when others move to intermittent sources like wind and solar, he said, would allow Utah to see its excess power on the market at a premium price, which would lower rates to Utah customers.

To some advocates who said that maintaining decades-old facilities would be expensive for the state, Albrecht said that over the years, they have been maintained “like your best historical race car.”

The quest for energy independence

When legislators speak about energy independence, they don’t mean isolating the grid in a Texas-like model, said Harry Hansen, deputy director at the Utah Office of Energy Development.

The Texas isolated grid system, designed to avoid federal regulation, affected millions during a severe winter storm in 2021 because the state had limited ways to receive help from its neighbors.

“The goal is to be able to sustain our own style of living and our own needs related to energy, not just electricity,” Hansen said. “So that we have that measure of cushioning, I guess, against any potential issues geopolitically.”

Albrecht agreed with that, arguing that Utah’s grid is interconnected with its surrounding states in the West. 

“All we’re saying is that we want to have enough energy for Utah customers,” he said. “We don’t want to be like Texas was and we want to be able to provide energy to other states who are making stupid decisions by going totally renewable.”

Utah’s energy production has been in decline since 2015, turning the state from an energy exporter to an importer in 2020, data from 2021 shows. “This new situation continued into 2021, with an even larger differential, and is predicted to continue in the near term,” a website associated with the Office of Energy Development reads. 

The state’s portfolio changed in the last two decades, going from 94% of coal-fueled electricity in 2000 to 57% in 2022. Renewables represented 15% of the grid’s contribution — up from 3% — while natural gas grew from 3% to 28%.

Hansen said that speaking about coal prioritization is a bit of a “mischaracterization.” It just so happens that coal fits the bills’ parameters of affordability, reliability and dispatchability, he said. 

Though other sources, such as geothermal have the potential to have a bigger capability, “right now the only baseload sources that Utah has are small amounts of hydroelectric or natural gas, (but mostly) coal here in Utah,” Hansen said.

Whenever those resources catch up with established resources, Albrecht believes the state could be able to revisit the newly approved energy policies. But more development in energy storage at a utility scale is needed to be able to sustain intermittent sources such as solar and wind.

“It’s got to be able to carry and store the resource for a day, a week, two weeks,” he said, “so that it can be released into the system at the time of the peak of the system.” 

Utah News Dispatch is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Utah News Dispatch maintains editorial independence.

Wyoming’s carbon capture mandate at coal-fired power plants saw several amendments last week and will head to the Wyoming Legislature’s Senate Appropriations Committee before potentially being considered on the Senate floor.

The Senate Minerals, Business and Economic Development Committee advanced Senate File 42 – Low-carbon reliable energy standards-amendments on a unanimous vote Friday. The bill would amend statutes created by Wyoming’s controversial 2020 law, House Bill 200 – Reliable and dispatchable low-carbon energy standards. The law requires utilities to study the viability of capturing carbon dioxide emissions from coal-fired power plants in the state — a multi-million dollar expense that their captive Wyoming ratepayers must cover.

Proponents of SF 42, including Gov. Mark Gordon, say the 2020 law must be updated — primarily to move a compliance deadline of 2030 back by several years to allow carbon capture technologies to advance and to garner more interest from private investors. Senate File 42 would also exempt utilities with fewer than 10,000 customers due to the financial burden of studying and potentially retrofitting coal plants with the technology. 

Actually implementing carbon capture at existing coal plants in Wyoming could come with a price tag of $500 million to $1 billion per coal unit, according to initial estimates reported by utilities Black Hills Energy and Rocky Mountain Power. There are five coal units currently under consideration for such retrofits.

“[House Bill 200] was never meant to be set in stone,” Gordon’s energy policy advisor Randall Luthi told committee members last week. “I welcome working with utilities on what amendments can actually make it more usable and get us to the end goal — and that is, let’s get some carbon capture units on coal-fired plants.”

Luthi admitted that retrofitting old coal plants — some of which range from 40 to 50 years old — might not be economically feasible. But if Wyoming can successfully demonstrate even a single carbon capture retrofit, it might convince other states to continue burning Wyoming coal and buying Wyoming coal-based electric power generation. “If we do that, there’s no reason that the technology cannot be exported — to those 26 other states that currently rely on Wyoming coal, and to other countries as well.”

But critics, including the Wyoming Office of Consumer Advocate, say Wyoming’s coal carbon capture mandate may not be worth salvaging. Aside from operational risks, the cost is simply too much, they say, because the entire financial burden will likely be borne by Wyoming ratepayers alone.

“[Senate File 42] explicitly says that not only final construction and operation of a carbon capture unit is in the best interest of ratepayers, but the costs of all work up to the point of operation, including analyses, engineering studies, pilot projects, and other testing and experimentation can be recovered [from] ratepayers,” said Shannon Anderson, attorney for the Sheridan-based landowner advocacy group Powder River Basin Resource Council. “It’s likely that the end result of all of that is going to be an absence of a viable project, and ratepayers will have paid millions into something that is never going to be put to useful life for customers in Wyoming.”

Moving targets

Luthi has argued that Wyoming can’t afford not to try to extend the life of aging coal-fired power plants in the state. Communities such as Glenrock and Rock Springs rely on the jobs and revenue generated by nearby coal-fired power plants, many of which may be retired in coming years.

Also, the staggering cost estimates to date are likely to come down, according to Luthi. The federal “Section 45Q” tax credit program for carbon capture and storage was expanded under the Inflation Reduction Act. The program should entice third parties to take on carbon capture retrofits so that Wyoming ratepayers are not on the hook for the expense, he said.

“Ideally, HB 200 would provide the framework where a company could come to a utility and say, ‘We’re willing to put that on there. We’re willing to pay for it,’” Luthi told the Senate Minerals Committee.

So far, utilities subject to the state mandate haven’t done a full analysis of cost recovery that could come from using carbon dioxide that’s captured at a coal smokestack and selling it for “enhanced oil recovery” — a significant potential revenue source, according to Luthi.

One issue that still needs to be worked out, committee members said, is what happens if a third party does not assume the cost of retrofitting a coal-fired power plant. Currently, Wyoming’s mandate includes a 2% cap on related costs that can be passed on to ratepayers. But the measure appears to merely allow up to 2% cost recovery at a time; it’s not a 2% limit for total costs, according to the resource council and Office of Consumer Advocate.

Instead of passing a bill to tweak several aspects of Wyoming’s coal carbon capture mandate, Anderson said, the Legislature should allow the utilities to seek an exemption, which is allowed under the current law. If cost analysis and engineering studies — which are underway — continue to suggest that retrofitting a coal plant is too expensive, the Public Service Commission may grant an exemption. Such a request and determination could come soon after Black Hills Energy and Rocky Mountain Power present their latest cost updates in March.

“Trying to fix HB 200 is a lost cause, in our opinion, and it will cost Wyoming real money,” Anderson said.

WyoFile is an independent nonprofit news organization focused on Wyoming people, places, and policy.

Only 5.2 GW of generation is scheduled to retire this year – a 62% decrease from last year’s 13.5 GW, and the lowest since 2008, according to EIA’s latest Preliminary Monthly Electric Generator Inventory report. Coal and natural gas account for 91% of planned capacity retirement.

Over the past two years, 22.3 GW of U.S. coal-fired generating capacity was retired, with only 2.3 GW scheduled to retire this year, accounting for 1.3% of the U.S. coal fleet in operation at the end of last year. Most of the retirements in 2024 will come from older units, with a capacity-weighted average age of 54 years, 10 years higher than the weighted average age of operating coal plants.

The largest retirements this year will be Seminole Electric Cooperative’s 626 MW Unit 1 in Florida, and Homer City Generating Station’s 626 MW Unit 1 in Pennsylvania.

However, coal retirements are expected to increase again in 2025, with operators planning to retire 10.9 GW.

For natural gas, the 2.4 GW scheduled to retire this year represents 46% of the total expected capacity retirements. The total accounts for 0.5% of operating U.S. natural gas-fired capacity, according to EIA.

A single unit will account for 60% of natural gas-fired capacity retirements this year: the final unit at the six-unit, 1,413 MW Mystic Generating Station in Massachusetts, which has been operating since the 1940s. The remaining capacity retirements will come from he Tennessee Valley Authority’s (TVA) Johnsonville station’s 16 simple-cycle combustion turbines, totaling 754 MW.

Finally, at least 450 MW of petroleum-fired capacity is planned to retire this year, with the majority coming from TVA’s Allen power plant, which is shutting down 20 combustion turbine units totaling 427 MW.

Firing existing boilers with hydrogen seems novel and new to many people. However, packaged boilers have been running on nothing but hydrogen for decades. Many boiler manufacturers have experience in dealing with hydrogen. They should be able to advise you on the peculiarities of burning it by itself or in combination with natural gas.

Hydrogen-based boilers are often found in refineries and chemical plants. The reason is simple. Hydrogen is often available in abundance in such facilities as a byproduct of other processes. Why waste hydrogen when you can harness it in boilers and eliminate fuel costs? But interest in hydrogen firing has broadened of late as one way to make progress toward decarbonization goals. Those running their boilers on natural gas, for example, can introduce some hydrogen into the mix to lower carbon emissions. In some cases, that may require a retrofit. Here are some points to consider for those interested in adding hydrogen to existing boilers.

Possible boiler modifications

There are certain technical factors that must be considered related to the combustion of hydrogen and how it compares to other fuels. Natural gas is denser than hydrogen. Hence, facilities will need a lot more of it by area than natural gas. This impacts the size of storage vessels and metering stations as well as diameter of piping and the size of valves. Valves and seals may also have to be replaced to prevent leakage. Those responsible for the design of the hydrogen supply system should be tasked with providing systems that can accommodate the higher volume of gas needed at the desired pressure and obtain the necessary BTU input for the boiler.

Pay attention, too, to impurities and water content in the hydrogen supply as they can shift the Wobbe Index of the fuel. While natural gas and hydrogen can have a similar Wobbe Index, the presence of a small amount of water, natural gas, or carbon dioxide can significantly lower the Wobbe Index.

Further, hydrogen combustion produces larger amounts of water than natural gas as a byproduct. Drainage systems and drying measures should take this factor into account. Coordination with burner manufacturers should help determine if any modifications may be needed to support the combustion of hydrogen.

Environmental systems

Environmental bodies now consider methane as a greenhouse gas as its combustion produces CO₂, sulfur dioxide, and nitrous oxide (NOx). By adding hydrogen to natural gas, CO₂ emissions can be reduced. However, hydrogen combustion does produce NOx as the peak flame temperature of hydrogen is higher than that of natural gas. Thus, hydrogen blending may lead to issues in meeting NOx targets. Some facilities may need to add flue gas recirculation (FGR) and selective catalytic reduction systems (SCR) to reduce NOx emissions from boilers blending hydrogen with natural gas.

Safety systems

The explosive range of hydrogen is greater than that of coal and natural gas. While methane ranges from a lower explosion limit (LEL) of 5% to an upper explosive limit (UEL) of 15%, hydrogen’s LEL is 4% and its UEL is 70%. Safety systems, therefore, will need to be upgraded to prevent leakage and mitigate the risk of explosion.

Consider, too, that some boiler components materials may have to be upgraded. Engineers should check the superheater and reheater for metal overstress and make any necessary surface adjustments. Depending on the distribution of heat transfer surfaces, higher or lower attemperation will also be required.

To keep retrofit costs down, packaged water tube boilers are probably the easiest type of boiler to gain experience in hydrogen combustion. Their flexibility and straightforward design simplify the addition of hydrogen while keeping risk relatively low.

Anyone moving forward with a feasibility study on a boiler retrofit for hydrogen is advised to conduct an evaluation of the entire boiler system. This should include all combustion equipment. It should examine potential changes in heating surfaces such as superheaters and reheaters, the possible addition of flue gas recirculation, attemperator capacity etc. As well as reviewing fans, air heaters, air ducts and overfire air systems, it should also encompass boiler control and automation systems, including the burner management system as upgrades may be needed there.

Certainty of hydrogen supply

Anyone wishing to fire their boilers with a blend of hydrogen better pay attention to supply. Hydrogen is far from widely available. There are projects that are receiving government funding to produce hydrogen using an electrolysis process. If a hydrogen electrolyzer exists or is being planned in your area, that may be one way to ensure regular supply.

Note that there are already plenty of gas turbines around certified to be able to run on 25% or more hydrogen. However, many of them continue to operate on 100% natural gas. Why? There isn’t any hydrogen available or if it is, the price tag is too high for boiler operation. Therefore, before investing heavily in hydrogen-related modifications to lower your carbon footprint, pay attention to the availability of hydrogen supply.

About the Author: Gerardo Lara is Vice President Fired Boiler Sales at Rentech Boiler Systems, Inc. of Abilene, TX. For more information, visit www.Rentechboilers.com.

The servicing of boilers in the field can be highly variable. Sometimes, everything runs smoothly according to routine. At other times, unforeseen challenges can rear their head and place project timelines in jeopardy. Shawn Brewer, Director of Business Development and Field Services at Rentech Boiler Systems, a company that has serviced hundreds of boilers, offered an example concerning boiler re-tubing.

A customer requests the repair of one or two leaky tubes. By all accounts, this should be a straightforward project. All that needs to be done is to shut down the unit, let it cool off, access the drum and execute the repair by rolling the tubes i.e., a rotating tool is placed into the tube end that expands the tube and tightens the seal between the tube and the drum. This kind of tube repair happens all the time. But it can happen that you arrive onsite to execute the repair and discover that the tubes are shot. They need to be completely replaced. That is a whole different ball game in terms of complexity and scope. In such a case, the boiler must be taken apart in the middle of the facility, noted Brewer. If the parts and manpower aren’t onsite, there will be a scramble to get them there immediately. Days can be lost.

To avoid such occurrences, here are best practices gleaned from long experience in servicing boilers.

Planning and coordination

There are many facets involved in the planning and coordination of a boiler servicing project. These include:

Know-how

Know-how is difficult to fake. Even if you manage it, you will eventually be found out. A best practice is to use an experienced technician as your initial point of contact, someone with deep experience in the field.  Such a person will ask the right questions, evaluate the job and figure out what it will take to fix the problem. This person must be able to establish how many people may be needed for a project, what other experts might be required on site and what type of testing should be done (such as for water quality). An inexperienced person in this role will be unable to differentiate straightforward projects from the trickier tasks that might require more time and labor. They may miss warning signs of trouble that lies ahead and allocate insufficient manpower, materials, tools and components. An experienced hand minimizes the chances of completely misestimating the potential scope of a new project.

Inspection

Don’t rely only on the work of one expert based on what the customer thinks might be wrong. Send someone onsite in advance to verify what is already known and find any unknowns that might interfere with a smooth in-and-out visit. Talk to the customer on the ground, have them walk you through the job, and show you what they think is wrong. Then investigate it yourself to determine what it will take to complete the job.

Contingency planning

No matter how good your first point of contact is or how well you scope things out on the ground, there is still a need for contingency planning. It is best to arrive on site with replacement components in hand and to be ready to deal with any other eventualities.

“Once physically inside a unit, you may find there is a lot more wrong than suspected,” advised Brewer. “An action plan in place and some kind of a contingency plan to tackle issues in a timely manner.”

On-the-ground coordination

Project coordination on the ground is just as important as advance planning. The field service team, plant management and maintenance personnel must work in concert to take the project to swift resolution. Brewer stressed that a key aspect of this is liaison with plant safety personnel to understand their safety protocols and align these with how you intend to operate while onsite.

Equipment access

Carefully measure entrances, sharp turns, headway clearances and the area around the boiler to isolate any areas of difficulty. You want to avoid problems such as semis with large boiler parts being unable to turn into a facility or unable to deposit the components close to where the work needs to be done due to congestion within the facility.

Work spaces

Workers on site often need a trailer set up nearby, an area where systems and components can be laid down and enough room to remove parts of the boiler and place them somewhere near. Make sure these spaces are not used by moving vehicles. On the other side of the coin, don’t obstruct areas of the plant where personnel need to have right of way. Having enough space to work near the boiler is another key point of coordination.

Timeline

In most cases, a short window is available for maintenance and repairs during an outage. During this period, be aware that other work may be ongoing and that these other projects may sometimes collide with your own. Those maintaining or commissioning a turbine, for example, may want the boiler fired up at the same point that you want it offline. Go over these points carefully in advance. Preparation is the way to avoid conflict, said Brewer. Make sure you can do the work needed on the boiler in the time apportioned by preparing well for whatever needs to be done.

Manpower

Due to retirements, cutbacks and lack of training of the new generation in industrial operations, there is a shrinking pool of skilled resources. Finding boiler expertise can be difficult.

“Be sure the company you bring in possesses trained and experienced resources to do the job and has others on hand in the case of unforeseen circumstances,” said Brewer.

Failure to do so could mean exceeding the planned outage window.

Provider selection

An industrial boiler is generally a custom piece of equipment operating as part of a specific process. Those servicing them must understand how the boiler integrates with other equipment in the plant. In a refinery, for instance, the boiler plays a role in most workflows. The output from crackers and other refinery equipment can grind to a halt without a working boiler. Thus, boiler errors in the field can prove very expensive.

“It is usually best to align with a reputable service team that is part of an established boiler manufacturer,” said Brewer. “Manufacturers possess the deepest knowledge of how boilers work and what it takes to put them together. Their service groups can call upon this knowledge to successfully repair units and overcome any challenges that may crop up.”  

Boilers are under tremendous strain and are integral to so many processes within the facility. They deal with high temperatures, big changes from hot to cold, pressurized steam, fuel combustion, humidity and condensation. Everything may not be as it seems from the outside. A small problem can quickly escalate due to the pressure extremes they operate under. Anytime there is even a small issue, it is best to act. Call your local service company and get somebody in to look at it before something more serious occurs.

Author: Drew Robb has been working as a full-time freelance writer in engineering and technology for the last 25 years. For more information, contact drew@robbeditorial.com.

The Senate has approved President Joe Biden’s nominee to lead the Environmental Protection Agency’s air pollution office just as the agency is set to finalize rules over climate-changing emissions from power plants and cars and trucks.

Joe Goffman is a longtime EPA official who has headed the air and radiation office on an acting basis since Biden took office three years ago. His nomination for the permanent post languished for nearly two years amid opposition from Republicans unhappy with EPA rules on a range of issues, from restrictions on coal- and natural gas-fired power plants to industrial soot and vehicle emissions.

Goffman’s 2022 nomination for the air post, one of the top jobs at EPA, lapsed last year without a Senate vote. He was renominated in early 2023. The vote to confirm him was 50-49, with West Virginia Sen. Joe Manchin, an ally of the coal industry, the lone Democrat to oppose him. Sen. John Barrasso, R-Wyoming, a vocal Goffman critic, was absent following the death of his wife, Bobbi, last week.

EPA Administrator Michael Regan said Goffman has played a central role in developing and executing rules and policies that deliver on Biden’s agenda to address the climate crisis and ensure clean air.

“Joe is uniquely skilled at building consensus among stakeholders and crafting policies that tackle global challenges like climate change, while at the same time addressing longstanding pollution concerns in overburdened communities,” Regan said in a statement.

Goffman’s office has overseen proposals that would impose strict limits on greenhouse gas emissions from power plants and other industries, as well as tailpipe emissions from cars and trucks and a separate rule addressing fine particulate matter, better known as soot. Those rules are set to become final later this year.

Sen. Tom Carper, a Delaware Democrat who chairs the Senate Environment Committee, hailed Goffman’s confirmation. The air office “has an outsized impact on our lives,” Carper said, with a mission that “includes reducing climate pollution while also improving our vehicle emissions standards and protecting public health.”

Goffman “has proven that he’s up to the task,” Carper added. ”Under his direction, EPA has made significant progress … to reduce greenhouse gas emissions and help lower energy costs for all Americans.”

But Sen. Shelley Moore Capito of West Virginia, the top Republican on the environment panel, slammed Goffman as a key author of job-killing regulations over two Democratic administrations. Goffman was a high-ranking EPA official in the Obama administration and played a leading role in the Clean Power Plan, President Barack Obama’s signature attempt to address climate change. The 2015 rule was blocked by the Supreme Court and was never enforced.

“Rarely do we have such a robust record to draw on in evaluating a nominee — and I say this with great disappointment — rarely is the record so damaging,” Capito said in a speech on the Senate floor.

“Mr. Goffman’s actions — marked by federal overreach and job-killing regulations — have been a disaster for our country,” Capito said. She called the Clean Power Plan “a direct shot at American energy production” and an attempt to shut down coal- and gas-fired power plants, including those in her home state.

An EPA plan to curb greenhouse gas emissions from power plants is little more than the “second iteration of the Clean Power Plan,” Capito said.

“Many of us have warned about the lawlessness and danger of this regulatory plan,” she said, predicting “disastrous consequences” on the reliability of the electric grid and energy prices.

Capito and other Republicans also denounced Goffman’s role in what they called the Biden administration’s rapid push toward electric vehicles.

Environmental groups defended Goffman.

“Our nation needs Joe’s extensive experience, knowledge and hard work as we tackle the increasingly urgent problems of the climate crisis and the air pollution that makes people sick,” said Fred Krupp, president of the Environmental Defense Fund. Goffman once worked for the group in a long career that also includes service as a Democratic staff lawyer on the Senate environment panel.

“Joe has dedicated his career to protecting human health and the environment” and will continue to do so “through decisions anchored in science and the law,” Krupp said.

As coal plants continue to retire in the energy transition, the United States is measuring a decline in C02 emissions. The Northwest region is no exception, as the Northwest Power and Conservation Council heard at its January meeting.

The Northwest has historically produced lower emissions compared to other parts of the U.S., the Council’s presentation said, largely due to its hydropower generation. Most existing coal plants in the region are scheduled to retire by 2030, and their capacity is set to be replaced by renewables.

Natural gas generated more power than coal in the region for the first time in 2018, and the NPCC expects an increase in gas plant utilization in the near term for the flexibility and reserves they provide. However, it expects few new plants to be built.

According to the U.S. Energy Information Administration (EIA), CO2 emissions declined 3% between 2022 and 2023, mostly driven by some coal-fired generation being replaced by renewable energy like solar power. The EIA expects this trend to continue into 2024, with CO2 emissions declining 1% relative to 2023. It forecasted an 18% decline in coal-related CO2 emissions in 2023 and a 5% decline in 2024.

In 2023, power plant owners and operators planned to retire 8.9 GW of coal-fired capacity, around 4.5% of the total coal-fired capacity at the start of the year. EIA said that substantial U.S. coal-fired capacity has retired over the past decade, and a record 14.9 GW was retired in 2015. The Northwest saw 58% of its regional emissions come from coal in 2022, compared to the 78% in 2012. As the region’s coal use has declined, its natural gas use has increased.

Renewable use is increasing in the region largely due to legislative support and lower costs, per the council. Much of the recent nationwide increase in renewable generation is the result of an expected 60 GW of new solar generating capacity entering service during 2023 and 2024. The EIA expects that the solar capacity increase, in addition to its forecast of increased hydropower generation and modest gains in new wind capacity, will reduce both coal-fired and natural gas-fired power generation in 2024.

PJM cited concerns about reliability impacts the retirement of Wagner Units 3 and 4 would cause.

“PJM and the affected Transmission Owner performed a study of the Transmission System and found reliability concerns (wide area voltage drop and thermal violations in several transmission zones) resulting from the deactivation of these generating units,” the RTO told Talen in a letter Jan. 4.

In October, Talen Energy told PJM it planned to retire the 834 MW Wagner plant, which consists of three oil-fired units and a natural gas combustion turbine unit, as of June 1, 2025, citing environmental permitting and economic reasons.

But PJM is urging Talen to wait to retire Units 3 and 4 until the 2028 timeframe, when it said the transmission upgrades would be completed. According to the RTO, these upgrades were part of a solution identified to address reliability violations following the announced retirement of the adjacent 1,295 MW Brandon Shores facility, also owned by Talen and also requested to deactivate on June 1, 2025.

The Wagner retirements will not warrant additional upgrades, PJM said. These issues are being addressed by a set of proposed projects (PDF) that would expand the regional transmission system to accommodate electricity demand growth, generator retirements and future capacity needs.

PJM requested that Talen continue to operate Wagner units 3 and 4 under a Reliability Must Run (RMR) arrangement until the planned upgrades are completed. Talen is requested to respond in 30 days.

While PJM cannot compel a unit to remain in service, it can formally request that the owner continue operating the unit to support reliability. This process, detailed in Part V of the PJM Open Access Transmission Tariff, offers a deactivating unit the opportunity to remain in service and recover its operating costs until all necessary transmission upgrades are in place.

The H.A. Wagner station is located outside of Baltimore in Anne Arundel County, Maryland.

The 359 MW Wagner Unit 3 was completed in 1966 as a coal-fired unit that Talen converted to run on fuel oil at the end of 2023. Unit 4, commissioned in 1972, is a 415 MW oil-fired unit. Wagner Unit 1 is a 133 MW natural gas-fired unit that was built as a coal-fired unit in 1956. Talen retired the 136 MW coal-fired Wagner Unit 2 in 2020.

In explaining the need to retire Wagner Units 1, 3 and 4, Talen Energy said the “limited run hours on the Wagner Facilities are not sustainable to continue operations, especially in light of the amount of time the Wagner Facilities have recently been running in the market.”

Talen said the Wagner Facilities’ Title V air permit limits operation to capacity factors under 15% when operating on oil.

Through this three-year partnership, Ambit will leverage Gecko’s newly launched AI-powered Cantilever platform that combines data-collecting robots, data integration, analytic tools, and software modules meant to reduce outages.

Optimizing Plant Performance is an educational track at the POWERGEN International® exhibition and summit, which serves as an education, business and networking hub for electricity generators, utilities, and solution providers engaged in power generation. Join us from January 23-25, 2024, in New Orleans, Louisiana!

“We are partnering with Gecko to drastically reduce forced outages,” said Steve Friend, Plant Manager of American Bituminous Power. “Until Gecko we have not been able to accurately predict where our equipment is going to fail before it does. With Gecko, we can stop these outages from happening by making smarter repairs, which at the end of the day is what improves energy reliability and affordability for our customers.”

Cantilever works by collecting data from assets using Gecko’s robotics and sensors. This data is then integrated with other data sources, such as maintenance records, operations history, and other business data, to provide a comprehensive view of asset health, identify damage, and recommend specific repair plans.

Gecko’s robots climb pipelines, boilers, tanks, ship hulls, and more in search of damage. Gecko’s software, in turn, is meant to enable human experts to contextualize that data and translate it into action. Cantilever is Gecko’s turn-key asset management solution, featuring robotic inspections, data integration, analytic tools, and software modules.