It represents the end of an era for the massive coal-fired plant, located near Farmington, New Mexico. The plant, which PNM had operated for decades, provided power for much of the state.

The shutdown of San Juan Unit 4 in September 2022 followed the retirement of Unit 1 in June of that year. The coal-fired plant had four units but was reduced to two in 2017, with the closure of Units 2 and 3. The plant first came online in 1973.

The plant’s retirement sent financial ripples through the surrounding communities. Hundreds of employees were impacted. PNM provided $11 million in severance packages to help about 200 displaced workers. About 240 mine workers received severance payments worth $9 million. Another $3 million went to job training.

PNM is the majority owner of San Juan Generation Station, but the city of Farmington has a 5% stake. The city had aimed to keep the plant open, partnering with Enchant Energy for a carbon capture and sequestration (CCS) project.

The San Juan Solar Project, which would have a capacity of 400 MW, is already on the power plant land and could start operating later this year. PNM approved a 20-year power purchase agreement (PPA) for the solar project.

Consumers Energy is closing all three coal units of the complex by 2025, 15 years earlier than originally planned. The utility said this closure will mark the company as one of the first U.S. utility providers to eliminate coal burning and is part of its Clean Energy Plan for a carbon-neutral energy grid by 2040.

The Campbell complex is slated to close by June 1, 2025. It is made up of three units that were built in 1962, 1967 and 1980. They are the last of 12 coal-fired units ― including those at the Cobb (Muskegon County), Whiting (Monroe County), Weadock (Bay County), and most recently, Karn (Bay County) plants ― that started closing in 2016.

As with the other plants, Campbell complex employees will be offered other job opportunities with the company. In partnership with community leaders, the site will be redeveloped following its demolition in 2026 or later.

In the meantime, Consumers Energy plans to offer bus tours of the Campbell complex on Sept. 21. People must sign up in advance for scheduled times, which are available on a first-come, first-served basis. The free tours will last about an hour, including an opportunity to go inside.

“We’re excited to give our friends and neighbors the opportunity to look inside Campbell as we make this major energy transition,” said Norm Kapala, Consumers Energy’s vice president of generation operations. “Our Campbell complex and the people who work here have served our state faithfully with reliable energy for generations. We want to provide an opportunity to understand and appreciate that legacy.”

The company purchased and started operating the 1,200 MW natural gas-fired Covert Generating Station in Southwest Michigan’s Van Buren County last year, matching most of the energy that Campbell provides. Consumers Energy continues to develop clean energy projects, including five Michigan wind farms and the Muskegon Solar Energy Center, which is slated to begin operations in 2026.

“We will be busy the next nine months as we continue to operate Campbell right up until it closes. We’re committed to a useful future for this property, but not before we take the time to reflect on the complex’s important work serving Michigan,” Kapala said.

The amount of coal transported in the United States decreased 8% in 2023, continuing a trend in which coal shipments have generally decreased over the past two decades as coal’s share of power generation has declined in the United States. The amount of coal transported to power plants, which are often located far from mines, decreased by more than half, falling from 957 million tons in 2010 to 422 million tons in 2023.

However, the U.S. Energy Information Administration (EIA) expects the decline in coal consumption to reverse this year. In its recently published July update to the Short-Term Energy Outlook, EIA forecast an increase in use of coal to generate electricity in the United States this year, with use dropping back to about 2023 amounts in 2025.

CenterPoint said respondents are encouraged to submit proposals that include utility-scale solar, wind and storage projects (standalone or paired), along with thermal generation, load-modifying resources, demand-side resources and other innovative solutions

“This RFP allows us to explore a wide range of technologies that can contribute to our long-term generation strategy,” said Shane Bradford, CenterPoint’s Vice President for Indiana Electric.

Proposals are due October 8, 2024, the company said.

Last year CenterPoint released its resource plan for Indiana, calling to reduce carbon emissions from its generation fleet by more than 95% over the next 20 years. This would include ending its use of Indiana coal by 2027.

At the time, the company said by 2030, it expected more than 80% of CenterPoint Energy’s electricity to be generated by solar and wind, with the rest provided by natural gas.

U.S. wind installations produced 45.9 gigawatt hours (GWh) of electricity in March 2024, eclipsing the 38.4 GWh generated by coal-fired power plants. The following month, coal-fired generation dropped to 37.2 GWh while wind generation blew away its previous high mark, churning out 47.7 GWh.

EIA included this lovely chart which demonstrates the steady growth of wind generation and the slow decline of our reliance on coal:

Installed wind power generating capacity has grown from 2.4 GW in 2000 to 150.1 GW in April 2024, according to the EIA. By contrast, many coal plants have retired over the past 25 years, and coal capacity has been roughly cut in half, from 315.1 GW in 2000 to 177.1 GW by April 2024. 22.3 GW of U.S. coal-fired electric generating capacity has been retired over the past two years, and operators plan to retire 2.8 GW more in 2024, data from EIA’s July Monthly Energy Review show.

Other sources of electricity generation have also increased as coal-fired generation has declined, notes the EIA. Since 2000, electricity from solar power has increased by 99.1 GWh, and generation from natural gas, which is often more price competitive than coal in electricity market dispatch, has gone up by 287.6 GWh.

And all good things, they say, never last

Wind power typically produces the most electricity in the springtime in the United States, so it’s not likely wind will permanently remain ahead of coal generation (at least not yet). During the first four months of 2024, coal-fired generation was 15% greater than wind generation in the United States.

You may recall something like this happening last year- when U.S. wind generation exceeded coal-fired generation for the first time in April 2023. It took 11 months later for that to happen again. But if you’re searching for silver linings, this spring marks the first time U.S. wind generation has exceeded coal-fired generation for two months in a row.

And there’s more capacity on the way. Operators expect 7.1 GW of wind capacity to come online in the United States in 2024, according to EIA’s July Monthly Energy Review. That’s a substantial amount, albeit a far cry from the 14 GW+ added in both 2020 and 2021, which were record years for growth in the industry.

And finally- a parting gift for those who either didn’t get the headline or understood the reference and now have that Prince slow jam stuck in their heads:

In their respective second-quarter earnings reports, NRG Energy and Vistra discussed potential opportunities for data center co-location.

NRG’s 21 generating sites are “ideally suited for new large loads and power plant development, offering co-location opportunities both behind and in front of the meter,” said NRG President and CEO Larry Coben on the company’s earnings call Thursday.

Coben said NRG’s facilities would be attractive to data center developers for their access to water for cooling, premium fiber channel access for low latency and existing grid access for rapid market entry. NRG’s fleet includes a mix of natural gas, renewables and coal.

“We were getting lots of people sort of throwing us bids for our sites,” Coben told investors.

He continued: “We know they think we’re just a bunch of power guys who don’t know anything about data centers. So, if that’s what they’re bidding us, we really need to look at this, because it means there’s a lot more value in there than the bids that we’re receiving.”

Regarding discussions with data center providers and any potential co-location deals, Coben said NRG was working on a strategy and would release more details later in 2024.

The concept of large loads co-locating with generation continues to draw interest. The most-watched proposal would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in Pennsylvania.

Multiple utilities protested the proposed Talen Interconnection Service Agreement (ISA), prompting FERC to call for a technical conference in the fall to discuss the larger issue of co-location.

For Vistra, the pending Talen case or upcoming FERC technical conference “has not slowed the conversation down” on potential data center co-location deals, said company President and CEO Jim Burke.

“We’re in due diligence for a number of sites,” Burke told investors on the company’s Q2 call. “This is a really big opportunity for our industry to meet customer needs.”

Vistra reiterated the company can provide data centers the speed to market advantage since there wouldn’t be the same level of buildout needed on the transmission side.

“I think there’s going to be plenty of data center load behind-the-meter or co-located, and also front of the meter,” Burke said.

On planning for load growth and building new gas plants

The industry’s rapid load growth is being driven by data centers, electrification and new manufacturing. This is compounded by the retirement of fossil-fired plants. As a result, both NRG and Vistra see emerging supply gaps and tightening markets.

Among the regions expected to experience a surge in demand, ERCOT’s current long-term load forecast shows peak demand increasing from 86 GW in 2024 to 137 GW in 2028. This load growth will require significant planning and construction of new generation and transmission.

While NRG and Vistra operate plants outside of Texas, most of their growth is taking place in the ERCOT market. Both companies are taking advantage of the Texas Energy Fund (TEF), a government low-interest loan program used to incentivize the development of more dispatchable generation and smaller backup power in the state.

NRG has filed TEF loan applications for three separate projects, totaling more than 1,500 MW of capacity. Thee company would begin construction on two of the three facilities as early as October of this year.

One of these projects is a new 689 MW natural gas combined-cycle unit with Mitsubishi Power M501JAC equipment, located at NRG’s Cedar Bayou plant in Baytown, Texas. The target completion date would be late-2027.

The 415 MW simple-cycle unit at TH Wharton would include Siemens Energy’s SGT6-5000F equipment and could come online by mid-2026.

Finally, the 443 MW simple-cycle unit at Greens Bayou would be powered by a GE 7HA.03 turbine and could be finished by mid-2028.

“We believe our projects are well-situated for a timely approval, given their shovel-ready nature and the completeness of the applications that we submitted,” said Coben.

Texas Lt. Gov. Dan Patrick recently said 81 applicants representing over 41 GW of dispatchable power had applied through the fund, as of May 31. Patrick said the state planned on expanding the program during the next legislative session.

Coben told investors NRG could apply for more loan funding in a potential second TEF round, but also noted the challenge of multi-year lead times for turbines and other equipment.

“If you don’t have a place in the turbine queue today, there’s no way you’re getting a new project online before 2030, at the earliest,” he said.

In May, Vistra announced plans to add up to 2,000 MW of natural gas-fired capacity in West, Central and North Texas.

860 MW of simple-cycle peaker plants would support West Texas, including the state’s growing oil and gas industry. The company is seeing multiple demand drivers, including data centers and the electrification of oil field operations, specifically the Permian Basin of West Texas

Vistra would also convert its coal-fired Coleto Creek plant near Goliad to natural gas after the plant retires in 2027. Repowering would enable up to 600 MW of gas-fired capacity.

Also included are 500 MW of augmentations at existing facilities, nearly half of which are already finished, Burke said on the Q2 earnings call.

In its quarterly report, Vistra leadership noted the industry continues to experience supply chain constraints and labor shortages that have reduced the availability of certain equipment needed for the construction of renewables projects. As a result, Vistra has deferred some of planned capital spend for these projects, the company said in its 10-Q filing.

The company did announce two long-term power purchase agreements (PPAs) with Amazon and Microsoft for two new large-scale solar facilities.

Supply chain disruptions have also increased the lead times to procure certain materials necessary to maintain Vistra’s natural gas, nuclear and coal fleet, according to the filing.

“We have proactively engaged our suppliers to secure key materials needed to maintain our existing generation facilities prior to future planned outages,” the company reported.

In its Q2 report, NRG said procuring mid to long-term generation through PPAs continues to be part of its strategy. The company has entered into renewable PPAs totaling nearly 1.9 GW with third-party developers, all of which were operational as of July 31.

In the U.S., most power plants begin increasing their coal stocks in the spring to prepare for the higher demand in the summer and winter. Additionally, U.S. power plants typically stockpile much more coal than they consume in a month, EIA said, with more than 90% of coal-fired power plants currently having enough coal to generate electricity for 60 days or more.

Coal-fired electricity has declined in the U.S. over the past decade, and coal plant stockpiles have been declining as well, EIA said. Coal consumption by the electric power sector totaled 385 million tons in 2023, 43% less than in 2016. Coal stockpiles reached 131 million tons by the end of 2023, 19% less than stockpiles at the end of 2016.

The amount of coal transported in the United States decreased 8% in 2023, continuing a trend in which coal shipments have generally decreased over the past two decades as coal’s share of power generation has declined in the United States. The amount of coal transported to power plants, which are often located far from mines, decreased by more than half, falling from 957 million tons in 2010 to 422 million tons in 2023.

However, EIA expects the decline in coal consumption to reverse this year. In its recently published July update to the Short-Term Energy Outlook, EIA forecast an increase in use of coal to generate electricity in the United States this year, with use dropping back to about 2023 amounts in 2025.

Although the amount of coal being transported closely follows the coal consumption rate, the two measurements can differ from year to year. During 2023, U.S. coal producers shipped 35 million more tons (9%) than U.S. power plants consumed. Surplus deliveries last year boosted inventory levels at power plants by 48%, reducing deliveries in early 2024. Conversely, coal shipments to power plants in 2021 and 2022 were 59 million tons less than the amounts consumed during those two years, and inventories dropped to less than 100 million tons.

Also, in late 2023, EIA projected that coal-fired power plants will generate less electricity in 2024 (599 billion kwh) than the combined generation from solar and wind (688 billion kWh) for the first time on record.

One of the largest generators in the U.S., Vistra, tapped McKinsey & Company to develop a machine-learning model to improve the efficiency and emissions of the coal-fired Martin Lake Power Plant in Rusk County, Texas.

The effort began when Vistra wanted to build and deploy a heat-rate optimizer (HRO) for the plant. The company worked with McKinsey data scientists and machine learning engineers from QuantumBlack AI to build a “multilayered neural-network model,” or an AI-powered algorithm that learns about the effects of complex nonlinear relationships.

The team fed the model two years of plant data to see which combination of external factors and internal decisions could produce the optimal HRO for any given time. External factors included temperature and humidity, and internal decisions included variables that operators can control.

It wasn’t a “one-and-done” solution, though. Vistra’s team continued to provide guidance on how the plant worked and identified data sources from sensors, which McKinsey said helped its engineers refine the model by adding and removing variables to see how the heat rate changed.

Through the training process and “introducing better data,” the models eventually made predictions with 99% accuracy or higher. After running the model through a series of real-world tests, the engineers turned the model into an “AI-powered engine.” After implementing the engine, the plant’s operators received recommendations every 30 minutes on how to improve the plant’s heat-rate efficiency.

“There are things that took me 20 years to learn about these power plants,” said Lloyd Hughes, Vistra’s operations manager. “This model learned them in an afternoon.”

With higher efficiency came more carbon reduction. Martin Lake was running more than 2% more efficiently after three months of operating with the machine-learning tool, which McKinsey said resulted in savings of $4.5 million per year and 340,000 tons of abated carbon.

Following the success at the Martin Lake Power Plant, Vistra distributed the AI-enabled HRO to another 67 generation units across 26 plants, which resulted in an average of 1% improvement in efficiency, McKinsey said, in addition to more than $23 million in savings.

Overall, Vistra’s AI initiatives have helped the company avoid around 1.6 million tons of carbon per year, McKinsey said.

Read the full case study here.

For perspective, AEP’s systemwide peak load at the end of 2023 was 35 GW. The utility serves 5.6 million customers in 11 states through its subsidiaries and has the country’s largest transmission system.

AEP Interim CEO Ben Fowke said the company continues to work with data centers to meet their increased demands for power, while ensuring that new contracts are fair to all of its customers.

“I want to emphasize that it’s critically important that costs associated with these large loads are allocated fairly, and the right investments are made for the long-term success of our grid,” Fowke told investors.

Fowke cited AEP filing new data center tariff proposals in Ohio and large-load tariff modifications in Indiana and West Virginia.

In Ohio, the proposed rate structure would require new data centers with loads greater than 25 MW and cryptomining/mobile data center operations with loads greater than 1 MW to agree to meet certain requirements before infrastructure is constructed to serve them.

Data centers specifically would be required to make a 10-year commitment to pay for a minimum of 90% of the energy they say they need each month – even if they use less.

Along with Exelon, AEP is also protesting a proposal that would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in northeast Pennsylvania. The utilities claim the proposed interconnection agreement would result in unfair cost burdens on ratepayers and negatively impact market operations and reliability.

According to a study published by EPRI in May, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used.

The burgeoning of data centers is one reason utilities are planning for the largest increase in natural gas-fired plants in over a decade. Buyers of F-Class, advanced-class and aeroderivative gas turbines are reportedly experiencing lead times not seen since the gas boom of the early 2000s.

AEP’s Public Service Company of Oklahoma (PSO) plans to seek regulatory approval for the purchase of Green Country, a 795 MW natural gas combined-cycle plant in Jenks, Oklahoma. Subject to approval, PSO expects to close on the transaction by June 30, 2025.

On impact of environmental regulations

In the utility’s 10-Q, AEP said federal rules and environmental control requirements would impact the utility’s generation fleet. AEP noted EPA’s suite of measures to crack down on pollution from fossil-fired plants.

Under one of the measures, coal-fired plants which plan to stay open beyond 2039 would have to reduce or capture 90% of their carbon dioxide emissions by 2032. As of June 30, 2024, AEP said approximately 46% of the company’s owned generating capacity was coal-fired.

AEP said it is in the early stages of identifying the best strategy for complying with the rule while ensuring resource adequacy.

The company, along with other utilities, states, companies and trade associations challenged the rule and requested a stay, which was denied by the D.C. Circuit Court of Appeals.

AEP and other utilities have now filed applications with the United States Supreme Court seeking an emergency stay.

The money comes from the Utilities’ Grant Funding Program, which is jointly funded by Arizona Public Service (APS), Salt River Project (SRP) and Tucson Electric Power (TEP). The funding allows for grant writing technical assistance and other forms of support to help develop new, sustainable economic strategies for residents and other stakeholders in impacted communities.

The following organizations were recently selected as grant recipients:

The Town of Eagar will receive a $25,000 grant to develop an updated general plan to replace the current version, which was written a decade ago. The updated general plan will identify areas of development, determine additional housing opportunities and craft a vision for the town’s future.

Apache County will receive a $25,000 grant to hire an engineering firm to write state and federal grants to support the design and construction of Phase II of the CR 8235 Stanford Road project.

The Town of Springerville will receive two grants. The first $25,000 grant will help fund the development of an updated master plan, the current version of which will expire in 2025. The master plan, a land use and infrastructure plan, sets forth local goals, objectives and policies to support community growth and redevelopment over the next two to three decades. The second $25,000 grant will match funding from the Water Infrastructure Finance Authority for new automatic meter readers, which will more accurately measure water usage, streamline operations and save water. 

Joseph City Unified School District will receive a $25,000 grant to match funds for an electric school bus that was awarded to the district through the second round of the EPA’s Clean Energy Grant.

APS, SRP and TEP pledged a combined $1 million in awards available through the Utilities’ Grant Funding program. Tribal, state and local governments, public schools, economic development groups and nonprofit groups within 75 miles of a closing or closed coal plant are eligible to apply.

A battle over the state’s energy future resumes Wednesday with utility regulators hosting a hearing on Georgia Power’s plans to significantly expand fossil fuel generation over the next several years.

The Public Service Commission has scheduled hearings starting Wednesday for Georgia Power’s application to fast track the construction of three methane gas-burning units at Coweta County’s Plant Yates in order to meet increasing demands in the next decade.

Wednesday’s hearing will feature testimony and cross-examination of Georgia Power officials, PSC staff analysts and experts representing clean energy groups. The hearing would resume on Thursday if the five member commission finds it necessary. There will be another opportunity for the company’s lawyers, environmentalists and consumer watchdogs to make their case to a PSC committee on Aug. 15, prior to the commission’s vote on the proposed Yates expansion scheduled Aug. 20.

The Plant Yates expansion was among the major changes approved in 2023 to Georgia Power’s three-year strategic plan, which was approved by the five-member commission in a 4-1 vote April 16. The utility company’s revised outlook also calls for bringing more renewable energy online with the addition of a total of 1,000 megawatts of solar capacity with battery storage by early 2027 and the extension of purchasing agreements in Florida for natural gas, and with Mississippi Power, a subsidiary of Georgia Power’s parent company Southern Co.

Yates expansion opponents argue that adding more polluting fossil fuels that will be in operation for nearly 50 years will do more long-term harm to public health and the environment than clean energy alternatives. Several environmental groups criticized the company for avoiding a competitive bidding process, which could result in ratepayers paying more for the projects to be built.

Plant Yates opened as a coal-fired electricity generating plant in 1950 and operated until five of the seven units were retired in 2015 and the other two were converted to natural gas.

Georgia Power officials have argued that the Yates gas generators project needs to be fast tracked in order to meet the growth of massive data centers that continue to proliferate, primarily around metro Atlanta. The new energy sources are being promoted as a way to keep attracting companies building state-of-the-art facilities that operate around the clock to support data storage and artificial intelligence technology.

The debate over Georgia Power’s utility rates has intensified over the last several years as customers faced hikes in electric base rates and paid for soaring fuel costs, coal ash cleanup and construction overages at Plant Vogtle. The average Georgia Power residential bill will jump a total of $44 a month over two years, including $16 to pay for spikes in methane gas and coal costs.

An expert witness for the Sierra Club and Southern Alliance for Clean Energy is urging the five PSC commissioners to delay the Yates certification until a new fuel recovery policy ensures that Georgia Power customers don’t have to pay 100% of the expansion costs.

“In order to serve the public interest, the commission is obligated to create the proper incentives so that major risks to the cost of the electricity market are optimized by the parties who have the information and power  to make those decisions,” wrote Albert Lin, a California based economic and financial consultant, in June 21 testimony.

The potential $3 billion costs to implement the three-year plan update, of which approximately half is alloted for Yates’  new units, has also raised concerns about how the burden would be split between residential and small business customers versus large commercial manufacturers.

Georgia Power officials also say the company will not seek to recover from its customers any construction costs overruns, unless it’s caused by events beyond the company’s reasonable control, such as natural disasters. The terms of  the revised resource plan stem from a stipulated agreement between Georgia Power, PSC staff, and various organizations such as consumer watchdog Georgia Watch, MARTA, the Georgia Association of Manufacturers and the Southern Renewable Energy Association.

Throughout the IRP update process, the PSC members have acknowledged that the Yates expansion would play a crucial role in meeting the energy demand to support Georgia’s “extraordinary growth”, according to Jeffrey Grubb, director of resource and planning for Georgia Power, and Michael Bush, director of generation development for Southern Co.

“The expedited certification of Yates 8-10 (units) is a necessary part of the company’s commitment to continue serving our customers reliably and cannot be delayed,” their July 10 rebuttal testimony says.

Georgia Recorder is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Georgia Recorder maintains editorial independence. Contact Editor John McCosh for questions: info@georgiarecorder.com. Follow Georgia Recorder on Facebook and X.