Under the agreement, B&W has received limited notice to proceed (LNTP) for the project. Notice to proceed for the full contract is expected in the fourth quarter of 2024, the company said.

B&W will convert the currently unspecified plant’s two coal-fired boilers – totaling more than 1,000 MW – to use natural gas fuel. B&W’s full scope would include the design and installation of new burners, air systems, fans and other equipment necessary to implement the fuel switch.

“Utilities across North America and throughout the world are evaluating options to extend the life of their thermal power generating assets,” said Chris Riker, Senior Vice President, B&W Thermal. “Replacing coal or oil with cleaner-burning fuels like natural gas, biofuels or hydrogen is often a cost-effective way for plant owners to lower emissions while maintaining reliable power generation capacity.”

Babcock & Wilcox said it will begin engineering and design work under the LNTP immediately with support from its affiliate, FPS. Babcock & Wilcox Construction will perform the construction portion of the project under an intercompany agreement when a full notice to proceed is received.  

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.

Austin Mayor Kirk Watson last month expressed concern that the city’s publicly-owned utility wasn’t planning a quick enough exit from Fayette, a three-unit, approximately 1,640 MW plant near La Grange, Texas. The plant is co-owned by Austin and the Lower Colorado River Authority (LCRA).

Watson had said he wanted Austin out of the Fayette Plant no later than January 2029.

But this week Austin Energy General Manager Bob Kahn told Austin city councilmembers that the utility would be pausing efforts to revise the city’s 2030 climate plan “to more thoroughly analyze generation resources and demand-side measures.”

“Significant proposed changes to the 2030 Plan contemplated by both Austin Energy and the [Electric Utility Commission] require us to further collaborate on how to achieve a carbon-free future,” Kahn said in a memo to elected officials.

Kahn said Austin Energy would be examining whether the city should stick with a mid-course 2030 update or if a 2035 benchmark would better align generation portfolio goals.

“Building new generation, whether renewable or conventional technology, requires years of planning and development work before the electricity source is operational,” reads the memo.

Kahn said Austin would also continue talks with LCRA to reach an exit of Austin Energy’s portion of the Fayette Power Project in a way that eliminates the operation of Austin Energy’s full ownership share.

Among other objectives, Austin Energy would explore the market potential of customer demand-side programs, release Requests for Proposals (RFPs) for various energy sources and further collaborate with stakeholders.

Kahn said Austin Energy would issue RFPs to gather more data around carbon-free generation technologies, including wind, solar, geothermal and hydrogen fuel cells. He said the utility would also be issuing RFPs pertaining to battery storage and “flexible-fuel generation.”

Austin’s energy is 70% carbon-free. The Fayette Power Project is Austin’s single biggest contributor to greenhouse gas emissions, representing three-quarters of Austin Energy’s emissions and about a quarter of Austin’s overall emissions, according to Mayor Watson.

Austin has co-owned the coal-fired plant with the Lower Colorado River Authority since 1979. Fayette Power Project Units 1 and 2 came online in 1979 and 1980, respectively. Unit 3 came online in 1988.

“As a partner in [Fayette Power Project], the city of Austin must meet its contractual obligations related to the plant,” said a spokesperson with LCRA. “We value our years-long partnership and look forward to working with the city of Austin in the future and hearing any proposal the city may bring forward.”

She added: “LCRA intends to continue operating the Fayette Power Project as long as it continues to provide reliable, cost-effective power.”

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.

These states include: Arizona, Colorado, Kentucky, Maryland, Montana, North Carolina, Pennsylvania, Utah, West Virginia, Wyoming and Wisconsin. 

Notably, TerraPower plans to build its Natrium reactor near a retiring coal plant in Kemmerer, Wyoming.

A 2022 DOE report found that more than 300 existing and retired coal power plant sites could convert to nuclear, dramatically increasing dispatchable, carbon-free energy as the country strives to meet its net-zero emissions goal by 2050. The department said each plant could match the size of the site being converted and help increase nuclear capacity by more than 250 GW — nearly tripling its current capacity of 95 GW. 

The DOE report also found that new nuclear plants could save up to 35% on construction costs depending on how much of the existing site assets could be repurposed from retired coal power plants. These assets include the existing land, the coal plant’s electrical equipment (transmission connection, switchyard, etc.) and civil infrastructure, such as roads and buildings.

DOE’s Gateway for Accelerated Innovation in Nuclear (GAIN) is conducting three feasibility studies to assess different aspects of repurposing coal power plant sites with nuclear power. 

This order allows NV Energy to move forward with ceasing coal operations at North Valmy Generating Station and transition to a natural gas-fired plant by the end of 2025. North Valmy is the company’s final coal plant in its portfolio. The two-unit, 522 MW facility is jointly owned by NV Energy and Idaho Power.

Unit 1, which went into service in 1981, produces 254 MW with a Babcock & Wilcox Boiler and Westinghouse turbine/generator. Unit 2 came online in 1985 and generates 268 MW with a Foster Wheeler Boiler and GE turbine/generator. Coal for the plant is shipped via railroad from various mines in Utah, Wyoming and Colorado.

PUCN also approved NV Energy’s plan to build additional transmission infrastructure to support continued growth in the state, including in the Apex area in the city of North Las Vegas – a growing center of economic development in Southern Nevada.

NV Energy also received conditional approval to begin developing the Sierra Solar project, a 400 MW solar site with a four-hour battery storage system in Northern Nevada.

While regulators approved the project, they expressed concern about its cost and said there would need to be ratepayer protections in the case of cost overruns.

The commission capped Sierra Solar’s construction costs at $1.5 billion and said NV Energy would need to pay credits to customers if the project doesn’t meet its completion goal of April 2027. Sierra Solar would be “the most expensive project ever proposed to be built or owned by NV Energy.”

The state of Nevada is aiming for a renewable portfolio of 50% by 2030 and 100% by 2050.

In 2023, New England had nearly 400 dispatchable generators and about 30,700 MW of generating capability, with 99.3% of electricity provided by natural gas, nuclear, hydropower, and imported electricity (mostly in the form of hydropower from Eastern Canada) and renewables. About 40,000 MW of new capacity is proposed to be built, the report said, and more than 7,000 MW of generation have retired since 2013 or may retire in the next few years, composed of mostly coal-fired, oil-fired and nuclear power plants. The region’s remaining two zero-carbon-emitting nuclear facilities, Millstone and Seabrook, supply a quarter of the electricity New England consumes in a year.

New England also had about 3,800 MW of of demand capacity resources (DCRs) and about 350,000 distributed solar power installations totaling 6,500 MW, with most installed behind the meter.

This number was calculated by adding total electricity generation and price-responsive demand reduction within New England to net imports from and exports to neighboring regions. The energy used to operate pumped storage power plants is then subtracted from that sum. Numbers are preliminary, pending the resettlement process.

Output from solar installations increased by 6% from 2022, rising to 3,851 GWh or 3% of the NEL. Wind power was relatively steady from year to year at 3% of NEL.

Oil-fired resources produced less electricity in 2023 than in 2022, accounting for 322 GWh, or 0.32% of the NEL, compared to the previous year’s 1,844 GWh. Production from coal-fired resources decreased from 320 GWh to 182 GWh, accounting for .16% of NEL for 2023.

All six New England states have renewable portfolio standards, which require electricity suppliers to provide customers with increasing percentages of renewable energy, ISO-NE said. Because large-scale renewable resources typically have higher up-front capital costs and different financing opportunities than more conventional resources, they have had difficulty competing in the wholesale markets. Therefore, the New England states are promoting, at varying levels and speed, the development of specific clean-energy resources to meet their public policy goals.

Several states have established public policies that direct electric power companies to enter into ratepayer-funded, long-term contracts for large-scale carbon-free energy that would cover most, if not all, of the resource’s costs.

About 97% of resources currently proposed for the region are grid-scale wind, solar and battery projects. As of January 2024, about 40,000 MW have been proposed in the ISO New England Interconnection Request Queue.

Energy storage represented 46% of the projects in the Interconnection Request Queue as of January 2024, and solar power accounted for 10%. Most solar power in New England is connected behind the meter directly at retail customer sites. Because such projects do not follow the ISO interconnection process, they aren’t reflected in the Interconnection Request Queue numbers.

The region had a total of about 350,000 distributed solar power installations as of December 2023 with a combined nameplate generating capability of approximately 6,500 MW. 

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.

That was the verdict from TVA’s Final Environmental Impact Statement issued by the federal utility Feb. 16 after a public review process last year over how to replace the coal-fired units at Kingston. TVA anticipates making a final decision in March 2024.

TVA mainly evaluated two options to provide at least 1,500 MW of generation to replace the capacity to be lost, plus additional capacity to support anticipated load growth.

The first option would include the construction of a single combined-cycle gas plant paired with 16 dual-fuel Aeroderivative combustion turbines, a 3 to 4 MW solar site and a 100 MW battery energy storage system on the Kingston Reservation. The combined-cycle plant would be capable of burning 5 percent hydrogen by volume at commissioning and 30 percent hydrogen with modifications to the balance of plant once a reliable source of H2 was identified, TVA said.

The first option would also include Eastern TN Natural Gas (ETNG) constructing and operating a 122-mile natural gas pipeline, gas compressor station and metering and regulator stations.

The second option would consist of constructing multiple solar and energy storage facilities at alternate locations, including in Eastern Tennessee. The construction of a pipeline would be subject to Federal Energy Regulatory Commission (FERC) jurisdiction and additional review.

TVA said its preferred option is the first. The federal utility said a combined-cycle plant paired with dual-fueled aero turbines would be the “best overall solution to provide low-cost, reliable energy to TVA’s power system, and could be built and become operational sooner” than the solar and storage in the second option.

The utility said it also preferred the gas plant option to provide the flexibility needed to bring 10,000 MW of solar onto the system by 2035.

‘Increased wear and tear’ for coal units

Kingston’s nine units can generate about 1.4 GW of electricity at capacity. The plant, located about 35 miles west of downtown Knoxville, entered operations in the 1950s.

TVA said frequent cycling of Kingston’s units, reflected in start-up and shutdown events, are currently averaging more than 85 times per year, which the utility said is outside the intended design of the plant.

This is resulting in “increased wear and tear, which presents reliability challenges that are difficult to anticipate and expensive to mitigate.”

TVA also said Kingston has experienced a “significant decline” in material condition over the last five years, including the need for repairs to the lower boiler drum, which the utility said are symptomatic of age-driven material condition failures which are difficult to proactively address.

The utility said based on these factors, it has developed planning assumptions for the timing of the proposed retirement of Kingston.

In general, TVA said its aging coal fleet is experiencing deterioration of material condition and performance challenges. Performance challenges are expected to increase because of the fleet’s advancing age and the difficulty of adapting coal within the changing generation profile.

TVA has reduced carbon emissions from its entire generating fleet by about 60% since 2005, thanks to a combination of closing coal plants and building solar and wind.