Alabama Power is paying less for power generated by third-party energy producers and imposing a cost for those companies to connect to its electricity grid.

The rule was approved by the Alabama Public Service Commission (PSC) in March; took effect in April and applies to companies that can generate at least 100 kilowatts of electricity.

Alabama Power said in an emailed statement the rates are updated each year, based on fuel costs and inflation, to keep prices as affordable as possible.

The company also said in a separate statement that the new integration cost is part of the monthly energy payment that the company pays to energy providers who are not Alabama Power customers.

Critics allege that the maneuvers are meant to stamp out competition in the market for electricity, especially for solar power providers looking to gain a foothold in the central and southern parts of the state and compete with Alabama Power.

“It is 100% about control,” said Steve Cicala, associate professor of economics at Tufts University, whose work focuses on the economics of regulation, particularly with respect to environmental and energy policy. “They are a business — and they don’t want competition.”

Daniel Tait, executive director for Energy Alabama, an advocacy group that hopes to increase renewable energy generation in the state, said Alabama Power was “trying to protect their monopoly, first and foremost.”

“It doesn’t really matter about the energy source,” he said. “Solar is just the one that is the most economical and the one most likely to challenge that monopoly, so that is why you see the fight on solar.”

The Alabama Public Service Commission said in a statement that the rate adjustments are appropriate based on the figures that Alabama Power provided.

“The cost is driven by the magnitude of the intermittency of certain generation, which requires additional operating reserves to maintain reliability on our system,” Alabama Power said in its email.

But some experts say the intermittency argument is overstated.

“We have gotten really good at predicting solar and wind output,” said Brendan Pierpont, director for electricity modeling for Energy Innovation, a nonpartisan energy and environment think tank. “These are large-scale industries in the U.S. and there are many gigawatts of wind and solar being developed each year.”

Both Energy Alabama and the Southern Renewable Energy Association, another group that promotes the responsible use of alternative energy, sought to challenge the PSC’s ruling, but the PSC officially denied their request in a written order on July 22.

Tait said Energy Alabama has decided not to challenge the order in court and will wait until the following year, should Alabama Power request a rate update or rule change with the PSC.

The Southern Renewable Energy Association said it is still considering its options.

Solar charges

The most recent rule changes limit revenues for larger renewable energy companies with power-producing plants. Those are separate from the households and smaller solar-producing companies that also generate electricity.

“The utilities have been lobbying for this for a long time,” said Gilbert Michaud, assistant professor with the School of Environmental Sustainability at Loyola University Chicago. “Utilities are having more competition in their sandbox, and they are saying, ‘We really don’t want more distributed solar generation because folks will buy less power from us. But we still have to maintain all our power plants and the grid infrastructure.’”

Brendan Pierpont, director for electricity modeling for Energy Innovation, a nonpartisan energy and environment think tank. said the ruling would discourage third parties from investing in renewable energy projects.

“While every solar project has different economic requirements, lowering the price a solar project receives or adding additional fees likely means fewer projects will get built, less investment in communities that would host those projects, few jobs in building those projects, etc,” he wrote in an email. “If the price received by a solar project is lower than the cost of operating Alabama Power’s own power plants, that’s also a missed opportunity for the utility’s electric customers to save money.”

The grid

Alabama Power, the largest utility in the state, has nearly 1.5 million customers and provides electricity to 57% of all customers in Alabama, according to a 2020 report published by the Southeast Energy Efficiency Alliance.

In February, Alabama Power filed a document with the PSC, the state’s electricity regulator, that proposed cutting the rates they pay for third-party electrical generation, known as a Contract for Purchased Energy (CPE), by up to 50%. In one category, the price decreased from about 7.33 cents per kilowatt hour to about 3.65 cents per kilowatt hour.

Those figures are formulated through a model and the values are estimated. That can be subjective, according to Pierpont of Energy Innovation.

“What they do is estimate low avoided costs, so they don’t have to pay very much,” Pierpont said. “In the meantime, they’re running coal plants and gas plants that cost quite a bit more than the rate they would be paying under this type of contract.”

Throughout the country, Pierpont said, power distribution companies like Alabama Power have been working to reduce the amount they pay homeowners who contribute electricity back to the grid through rooftop solar panels.

In addition to the lower rate payments, Alabama Power introduced a Variable Integration Cost at $0.00193 per kilowatt hour for third-party companies. That would further reduce the revenue that those firms receive for energy purchased by Alabama Power.

Pierpont found a few examples of utility companies imposing an integration cost to connect to the system. One is PacifiCorp, an energy company that operates in several western states, and the second is Duke, which is in the Carolinas.

“This approach seems fairly rare and limited to regions without competitive electricity markets,” Pierpont wrote in an email.

Significant costs

Energy Alabama published a blog post in June alleging that the charges, which it called a tax, would amount to a $250,000 annual charge for an 80-megawatt solar farm based in Montgomery.

The updated rates, along with the integration cost, are separate from the charges that Alabama Power imposes on individual households who install solar to offset their electricity bill.

In 2012, the PSC approved an Alabama Power request to impose a $5 per kW Capacity Reservation Charge (CRE) on customers with solar panels, often known as a rooftop fee. Typically, households that generate about 5 kW on their solar array will pay about $300 annually, or $9,000 over the 30-year expected lifespan of the system.

That charge has since increased to $5.41.

Power companies in other states have been allowed to impose such charges, including Arizona. Michaud, at Loyola University in Chicago, estimates that residents in almost a third of all the states in the country must pay such a fee. Michaud said the fees are clustered “in more conservative states, like the U.S. South.”

This makes it less economical for households to install solar panels for their homes because they make up the upfront fixed cost of the system from the savings generated from their power bills, and lengthens the time needed to recoup the cost of the system.

“It is basically killing your payback period, or at least increasing it,” Michaud said. “I would do this in my class, and a lot of students find, ‘Hey, this increases the payback period from 10 years to 14 years.’ You are having folks paying for a longer time.”

‘Intermittency of certain generation’

For its part, Alabama Power said the rate adjustments to third-party energy providers, also known as the CPE, and newly imposed integration cost, are necessary for maintaining price stability for customers.

“Rate CPE keeps electricity costs stable for customers by ensuring Alabama Power pays a fair price for energy,” the company said in an emailed statement. “This approach, updated annually, protects customers from unexpected price shocks linked to fluctuating energy production costs.”

The company said that the Variable Integration Cost is not a fee and is factored into the calculation that Alabama Power pays third-party producers who are not customers of Alabama Power and who sell all their output to the company.

“The cost is driven by the magnitude of the intermittency of certain generation, like solar, which requires additional operating reserves to maintain reliability on our system,” the company said.

When electricity is in high demand, electricity third-party providers contribute is highly valuable. The power becomes less valuable very late in the evening or very early in the morning, the times when people are asleep, not very active, and have no need for electricity. Smoothing out the supply when the need is uncertain is a tricky question to answer.

Timothy Charles Lieuwen, a professor of engineering at Georgia Tech University, said that over time, the price power distribution companies have been willing to pay to third parties who generate energy has declined.

“It is a really hard question, what is the value of the power they (third party energy providers) are providing,” he said.

Power distribution companies, including vertically integrated ones such as Alabama Power, are less willing to purchase power from other companies in the face of that mounting uncertainty about when customers will need that energy.

The Public Service Commission deferred to Alabama Power in an emailed statement.

“The adjustments to Rate CPE (Contract for Purchased Energy) were found to be in the public interest because they accurately reflected Alabama Power Company’s most current projected avoided cost,” the statement said. “Alabama Power’s projected avoided costs are updated annually. The variable integration charge was approved because it mitigates the cost incurred with integrating the intermittent output of QFs (Qualifying Facilities) onto the Southern Company System.”

The Public Service Commission said in its statement that allegations that it gave Alabama Power more control over the electricity production market were not valid.

“The matters approved in the Commission’s March 5, 2024 Order in Docket U-5213 were designed to accurately establish the projected avoided cost rates for CPE and to allow for the recovery of the cost incurred by Alabama Power in integrating the intermittent output of QFs onto the Southern Company System,” the statement said.

Tait called Alabama Power’s claims about intermittency “absurd.”

“Basically, what Alabama Power is saying when they say something like that is, ‘Our engineers are dumber than everybody else’s engineers and they can’t figure this out,’” Tait said. “Alabama Power’s engineers are just as smart, and just as talented, as everybody else is.”

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

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.

The total $1.1 billion investment in Indiana’s Pike County would take place from 2024 to 2026.

Petersburg Generating Station Units 3 and 4 would be repowered from coal to natural gas by the end of 2026. AES Indiana anticipates being the first utility in Indiana out of coal, pending approval of the project from state regulators.

The Petersburg Energy Center would add 250 MW of solar and 180 MWh of battery storage to AES Indiana’s portfolio. The project is currently under construction and expected to be operational by the end of 2025.

AES Indiana’s 2022 Integrated Resource Plan (IRP) includes transitioning coal-powered units to natural gas and adding wind, solar and battery storage capacity over the next five years.

Recently, AES Indiana acquired 100 percent interest in Hoosier Wind, a 106 MW wind project in Benton County and announced the commercial operation of the Hardy Hills 195 MW solar project in Clinton County.

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.

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.

WASHINGTON (AP) — In a victory for President Joe Biden’s administration, a federal appeals court on Friday ruled that a new federal regulation aimed at limiting planet-warming pollution from coal-fired power plants can remain in force as legal challenges continue.

Industry groups and some Republican-led states had asked the court to block the Environmental Protection Agency rule on an emergency basis, saying it was unattainable and threatened reliability of the nation’s power grid.

The EPA rule, announced in April, would force many coal-fired power plants to capture 90% of their carbon emissions or shut down within eight years. The rules are a key part of the Democratic president’s pledge to eliminate carbon pollution from the electricity sector by 2035 and economy-wide by 2050.

A three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit rejected the industry request to block the rule, saying the groups had not shown they are likely to succeed on the merits. Nor did the case invoke a major question under a previous Supreme Court ruling, since the EPA claimed only the power to “set emissions limits … that would reduce pollution by causing the regulated source to operate more cleanly,” the appeals court ruled.

The unanimous ruling also rejected the claim of immediate harm, saying compliance deadlines do not take effect until 2030 or 2032.

The ruling was issued by Judges Patricia Millett, Cornelia Pillard and Neomi Rao. Millett and Pillard were appointed by President Barack Obama, a Democrat, while Rao was named to the court by President Donald Trump, a Republican.

Environmental groups hailed the ruling, saying the court recognized the EPA’s legal responsibility to control harmful pollution, including from greenhouse gas emissions. The power sector is the nation’s second-largest contributor to climate change.

“Americans across the nation are suffering from the intense heat waves, extreme storms and flooding and increased wildfires caused by climate pollution,” said Vickie Patton, general counsel of the Environmental Defense Fund, which filed a friend-of-the court brief in the case. The EDF and other groups “will continue to strongly defend EPA’s cost-effective and achievable carbon pollution standards for power plants,” she said.

Meredith Hankins, a lawyer for the Natural Resources Defense Council, said the EPA rule “set reasonable standards for utilities and states to cut their carbon pollution.” The searing heat wave hitting much of the nation is a sign of how much the rules are needed, she said.

“The idea that power producers need immediate relief from modest standards that start to kick in eight years from now was obviously absurd,” Hankins added. West Virginia and other states that challenged the rule “have plenty of time to begin their planning process” to comply with the rule, she said.

The National Mining Association, which joined the legal challenges, said it would seek an emergency stay from the Supreme Court.

“The stakes couldn’t be higher. The nation’s power supply is already being pushed to the limit, and this rule flies in the face of what the nation’s utilities, grid operators and grid reliability experts tell us is needed to maintain grid reliability,” said Rich Nolan, the group’s president and CEO.

Nolan and other industry leaders said the rule would force the premature closure of power plants that are crucial to maintaining grid reliability even as demand for electricity surges.

Timothy Carroll, a spokesman for the EPA, said the agency was pleased that the court allowed the power plant rule to go into effect while litigation continues.

“EPA’s final standards will significantly reduce emissions of harmful carbon pollution from existing coal-fired power plants, which continue to be the largest source of greenhouse gas emissions from the power sector,” Carroll said.

The EPA projects that the rule will yield up to $370 billion in climate and health net benefits and avoid nearly 1.4 billion metric tons of carbon pollution through 2047, equivalent to preventing annual emissions of 328 million gasoline-powered cars.

The power plant rule marks the first time the federal government has restricted carbon dioxide emissions from existing coal-fired power plants. The rule also would force future electric plants fueled by coal or natural gas to control up to 90% of their carbon pollution.

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.

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.

American Electric Power (AEP) recently issued a request for proposal (RFP) for the supply of coal to one or more of its generating stations in multiple coal regions. AEP is seeking proposals for the following regions and terms, but will consider longer-term proposals should the parties be able to agree on mutual terms and conditions.

The RFP was issued for the following regions:

• Central Appalachian Basin (Term: 2025, 2026)
• Illinois Basin (Term: 2025, 2026, 2027)
• Powder River Basin (Term: 2025, 2026)
• Northern Appalachian Basin (Term: 2025, 2026, 2027)
  

Proposals are due by 5 p.m. ET, Friday, Aug. 2, 2024. Proposals will be kept open until 5 p.m. ET, Friday, Sept. 6, 2024, AEP said.

AEP issued a similar request in 2021 seeking fuel for its coal-fired power generation plants to supply through 2024. Overall, the RFP sought contact on more than 19 million metric tons of coal from the Central Appalachian, Illinois, Powder River and Northern Appalachian basins. These four mining regions produce most of the nation’s coal.

Like many U.S. utilities, AEP has been retiring and replacing a large part of its coal-fired generation portfolio. The company still generated 42% of its power from coal-fired plants in 2023.

AEP’s operations span across several states, many of which are within the PJM Interconnection. Use of coal-fired power in PJM territory has dropped over the last decade, largely driven by the buildout of natural gas combined-cycle (NGCC) plants and higher relative fuel costs, according to the U.S. Energy Information Administration (EIA).

In 2023, the use of coal-fired generation in PJM fell to 34% of capacity. Yet coal generators were dispatched less frequently last year, contributing 14% of PJM’s generation, while making up 18% of its generating capacity. By comparison, in 2013, the capacity factor of coal-fired power in the market was 56%, when coal made up 44% of the market’s generation and 38% of its capacity, EIA said.

PJM is the largest wholesale electricity market in the nation and includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and Washington, D.C.

For 20 years, the U.S. Environmental Protection Agency (EPA) regulated coal-fired power plants through litigation using a revised interpretation of the routine maintenance exemption in the New Source Review (NSR) regulations. This national compliance initiative ended in 2019 after affecting 113 plants at a cost of $21 billion (as shown in the below figure). However, a new proposed NSR rule change could have a similar significant effect on the power industry.

The big problem with the routine maintenance exemption was the lack of a definition for “routine” and the subsequent after-the-fact evaluations of projects by EPA. At plants grandfathered under NSR [(e.g., operating without best available control technology (BACT)], industry made repairs and undertook projects that it considered to be routine (boiler retubing, turbine overhauls, etc.) without first seeking an NSR permit. In the 1990s, when EPA realized these older plants had never undergone NSR permitting, EPA reevaluated “routine” and decided that these repairs retroactively needed NSR limits and controls. “Routine maintenance” was a powerful tool in shutting down many coal-fired boilers.

On February 22, 2024, EPA proposed several revisions to its NSR preconstruction permitting regulations.^[1] In another of EPA’s unfortunate acronyms,^[2] these rules are referred to Project Emissions Accounting (PEA, 2020) Rule and the Project Emissions Accounting Rule Reconsideration (PEAR, 2024). The two rules were meant to clarify issues resulting from the mostly failed 2002 NSR Reform Initiative and the rule interpretations in intervening years.

PEA and PEAR attempt to formally define a project, to wit, what activities are included when calculating and comparing emission increases to the NSR permitting thresholds. For example:

• How many years separation are required before two activities are considered a single project?
• Does a project include just the new emissions or also the associated emission unit decreases?
• What makes an emission decrease enforceable when replacing an old unit?

Industry seeks clarity and certainty when interpreting environmental regulations. Failure to obtain the correct permit is costly (see Figure above). The group of activities that constitute a project is virtually always site-specific. Substantial comments (due July 2, 2024) were received on the draft regulation.

For example, EPA proposed the following revisions to the definition of project (revised text is in bold):

Project means a discrete physical change in, or change in the method of operation of, an existing major stationary source, or a discrete group of such changes (occurring contemporaneously at the same major stationary source) that are substantially related to each other. Such changes are substantially related if they are dependent on each other to be economically or technically viable. In an extreme ozone nonattainment area, a “project” means each discrete operation, emissions unit, or other pollutant-emitting activity.

Comments from industry groups, regulators and tribal organizations varied widely. The proposal was a much-needed improvement, it included a presumption that industry was trying to circumvent the regulations, and it imposed unjustified recordkeeping and reporting. The proposal manages to please no one completely and annoy everyone in differing ways. Commenters argue that “discrete” is poorly defined, the test for “economically viable” is not provided, and removing the previous guidance that two projects divided by more than three years are separate is ill-advised.

Additionally, commenters argue permitting each reduction could be onerous, EPA failed to identify any instance in which a failure to properly define a “project” altered the applicability determination and/or led to circumvention of NSR preconstruction permitting requirements, and reporting requirements are vague enough to be applicable to new office equipment.

NSR is a poorly written regulation, influenced by lobbyists and corrupted by 50 years of litigation. Like the 2002 NSR Reform attempt, this proposal, and in fact the entire NSR program, is subject to political winds and capricious legislative whims. When combined with the recent Supreme Court assassination of the Chevron Deference (when in doubt, defer to the experts at the regulatory agencies), power plants stagger under increased regulatory uncertainty. Redefining projects has the potential to impact the power industry as significantly as the reinterpretation of “routine”.

What should you do?

• Acknowledge that PEA/PEAR is a big deal, and it will affect your operations.
• Consult an attorney before each outage and project.
• Conduct NSR netting calculations to set baseline emissions before each outage and project.
• Document project emissions, including reductions, in-house and potentially with your regulator.
• Consult with your regulator to understand what permits are required before and which emissions reports are required after each post outage/project.
• Follow this rule in industry groups to understand how it evolves.

References

¹ 89 Fed. Reg. 36,870 (May 3, 2024) Docket ID EPA-HQ-OAR-2022-0381

² See CSAPR pronounced Casper

About the Author: Robynn Andracsek, PE, is a Senior Air Quality Engineer at Providence Engineering and Environmental Group LLC with 26 years of experience in air permitting for utilities and district energy facilities.  Providence is an employee-owned, multidisciplinary engineering and environmental consulting firm. Our work has taken us across the United States and beyond in support of our governmental and industrial clients’ goals and challenges all the while holding an unwavering dedication to our founding principles – to take care of our clients, make a little money, and have fun while doing it. Her email address is robynnandracsek@providenceeng.com.