This week, the Solar Energy Industries Association (SEIA) announced it has hired Tim Pawlenty, the former Republican Governor of Minnesota and one-time GOP Presidential primary candidate, as its next President and CEO.

In the press release, Pawlenty stated:

The sun is the safest, most natural, and largest nuclear reactor in the world, and it provides an abundant source of energy we should be using to its fullest potential. That’s why solar is one of the most effective tools we have to meet rising energy demand while lowering costs for families and businesses. At a time when affordability is front and center for Americans, expanding access to low-cost solar and storage can deliver real savings and strengthen our domestic energy supply.

Unfortunately, Pawlenty’s comments about solar lowering costs for families are divorced from the data, and his own energy legacy as the Governor of Minnesota is one of making electricity less affordable for families and businesses.

Why Hire T-Paw?

Before we address how Mr. Pawlenty’s wind and solar mandates drove up electricity prices in Minnesota, it’s worth exploring this key question: Why Tim Pawlenty?

Simply put, the solar industry’s ability to renew the federal subsidies that have bankrolled it is jeopardized by the plummeting favorability ratings of wind and solar among Republican voters and policymakers. Pawlenty was almost certainly hired to stem the bleeding and renew the subsidies.

A recent Pew survey found that support for prioritizing wind and solar development over fossil fuels has dropped from 65 percent of Republican and Republican-leaning voters in 2020 to just 28 percent in April of 2026. It’s interesting to note that support has also dropped slightly for Democrat/Democrat-leaning voters.

Furthermore, Republican voters are far more likely to (correctly) believe that solar is less reliable and more expensive than other energy sources than Democrats and U.S. adults as a whole.

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Restoring the subsidies set to expire under the One Big Beautiful Bill Act (OBBBA) will first require restoring solar’s image among just enough conservative lawmakers to extend the subsidies in the coming years. This is how the “temporary” wind Production Tax Credit (PTC) has been in place since 1992.

Conservative Lipstick on A Green Pig

Hiring Pawlenty to lead the solar industry lobbying arm continues a longstanding tradition in which left-leaning climate foundations and wind and solar advocates fund conservative-branded advocacy groups to use conservative-sounding language to trick conservative lawmakers into supporting liberal energy policies.

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These groups include the Conservative Energy Network, the American Conservation Coalition, Citizens for Responsible Energy Solutions, the R-Street Institute, and others.

Popular talking points have included “letting the free market decide,” while ignoring the mandates and subsidies that are the lifeblood of the industry, and promoting “all of the above solutions,” while liberal policymakers imposed onerous regulations on coal, nuclear, and, to a lesser extent, natural gas plants.

These groups rely on the fact that many people don’t realize that there is no free market for electricity, especially not when subsidies, mandates, and regulations exist to favor certain energy resources over others and exploit this ignorance for their own financial gain.

Pawlenty’s Energy Legacy: Mandates, Higher Prices

Tim Pawlenty said in the press release that adopting “low-cost solar and storage can deliver real savings.” However, we already have ample evidence that solar has not led to energy savings, and we can use Pawlenty’s history as Governor of Minnesota as an example.

In 2007, Pawlenty signed Minnesota’s Next Generation Energy Act (NGEA), which required electric utilities to generate 25 percent of their electricity from “renewable” electricity sources by 2025. But the legislation was effectively a wind-and-solar mandate because it specifically excluded large hydroelectric power facilities in Canada from qualifying.

At the time, this was significant because it was one of the most ambitious renewable mandates in the country, and the most ambitious in the Midwest, along with Illinois. Only Maine and Connecticut had higher targets, while Oregon and Illinois matched Minnesota’s 25 percent by 2025 mandate.

Prior to enacting the NGEA in 2007, Minnesota’s all-sectors electricity prices were, on average, 18.5 percent below the national average, giving the state’s energy-intensive industries, such as mining, manufacturing, and agriculture, a competitive advantage relative to the rest of the country.

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Minnesota met the mandated renewable electricity percentages eight years early, but at a steep price. By 2017, the state’s all-sectors electricity prices were only 2 percent below the national average, residential rates were 1 percent higher, and industrial rates were 7 percent higher—effectively erasing Minnesota’s historic edge as a low-cost electricity state.

While many factors affect retail electricity prices, and Minnesota’s cost premium relative to the national average has shrunk as other states have gotten more expensive, Pawlenty’s mandates locked Minnesota into large-scale wind procurement during the most expensive phase of the modern wind buildout.

Data from NREL show many wind projects entering service between 2007 and 2012 carried costs near or above $80 per megawatt-hour in 2021 dollars before prices declined later in the decade. In other words, Minnesota ratepayers were forced to pay an expensive premium for wind thanks to Pawlenty’s mandates.

These high-priced wind contracts contributed to higher costs for families. From 2007 to 2017, Minnesota families saw their electricity bills rise from $76.40 per month in 2007 to $97.58 per month in 2017—an increase of 28 percent—despite a 10 percent reduction in electricity consumption. In essence, Minnesota families and businesses were forced to pay significantly higher electricity bills even as they used less power.

Based on Pawlenty’s past track record with respect to energy affordability, Americans should be exceedingly skeptical of his claims that solar will reduce energy costs.

Levelized Cost of Solar

As many of our readers know, the solar industry’s claim to affordability rests on its misuse of the levelized cost of energy (LCOE) metric. However, LCOE measures the stand-alone cost of generating electricity at a single facility, but it does not account for the additional transmission and backup power costs needed to maintain grid reliability when the sun isn’t shining.

Always On modeled the LCOE of new resources in Indiana (a future article on this is forthcoming) and found that, including firming costs, the unsubsidized cost of wind increased from $76.79 per megawatt-hour to $159.24 per megawatt-hour, compared with $65.03 per megawatt-hour for new natural gas combined-cycle plants.

There is also the inconvenient truth that, according to Lawrence Berkeley National Labs, solar prices have increased by 25 percent since 2022, falling national average capacity factors since 2016, higher financing costs since 2020, and, most recently, increasing capital costs.

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Conclusion

Our modeling shows solar can’t compete with other energy sources without the federal taxpayer handouts Mr. Pawlenty claimed to oppose during his 2012 presidential run.

Back then, he told a group assembled in Iowa “the truth about federal energy subsidies… is that they have to be phased out,” continuing to say that “we simply can’t afford them anymore.” This begs the question: if we could not afford federal energy subsidies when the national debt was a mere $16.4 trillion in 2012, how can we afford them now that it is $38.95 trillion?

Time will tell whether Tim Pawlenty will flip-flop on his previous stance on subsidies at his new job, but if this were a wager on Polymarket, we would smash the over.

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24/7 Renewables? A Reality Check on IRENA’s “Firm” LCOE by

The Gas Turbine: The final revelation in the pantheon of prime movers by

250+ onshore wind projects stalled as Pentagon freezes permitting by Canary Media

Another commenter stated that Democrats’ and Independents’ views of the environment likely shift when Republicans hold the White House because they view the environment as inextricably linked to climate, while Republicans don’t think about climate at all.

The Gallup data appear to support this claim for Democrats and Republicans. Climate change was the top environmental concern for Democrats, with 72 percent worrying about it, while climate change ranked last for Republicans, with only 6 percent worrying about this issue.

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Independents, for their part, care about climate, but less so than other environmental issues like having access to clean drinking water, pollution in lakes and rivers, and air pollution.

While an overwhelming majority of Democrats worry about global warming or climate change and its impact on people, plants, and ecosystems, few appear to be aware that their preferred solutions to mitigate future warming—i.e., wind and solar power—would cause more immediate warming in the United States than reducing our emissions would offset.

Before we get into it, check out Mitch’s discussion on Fox 5 Live Zone with host Guy Lambert about President Trump’s Ratepayer Protection Pledge and background on why it’s needed in the first place.

Warmed with the Wind

A 2018 study by Harvard scientists, published in the academic journal Joule, modeled the temperature impacts of scaling up wind turbines to meet all U.S. electricity generation and found that doing so would significantly increase local surface temperatures throughout the country.

It is important to note that the wind turbines do not produce new warming. Instead, they increase surface temperatures by redistributing heat in the air that already exists. This occurs when the blades cause turbulence, mixing warmer air that has risen with cooler air near the ground, as shown in the infographic below.

Wind-induced warming would increase surface temperatures in the “wind farm region” by an average of almost 1.1 to 1.4°F (0.6°C), while surface temperatures throughout the Continental US would increase by about 0.5°F (0.24°C), which you can see in the graph below.

In contrast, the study found the cooling impact of reducing emissions would be very small. U.S. temperature reductions from lowering our domestic emissions would be around 0.2 to 0.4°F (around 0.16°C) by 2100.

Furthermore, the warming from wind is larger, more localized, and immediate, affecting the people, plants, and animals living near the turbines today, while the avoided warming effects of reduced greenhouse gas emissions are smaller, spread out globally, and would not offset the wind-induced warming experienced before 2100.

Where the Wind Warms

According to the study, the Great Plains and Midwest would be the most impacted by wind warming, as they are expected to host roughly 1.3 to 1.5 million megawatts (MW) of wind capacity needed to meet the average U.S. electricity consumption.

For reference, there are only about 150,000 to 160,000 MW of wind currently installed in the United States, which means it would take roughly 10 times as many turbines to meet the annual energy needs of the country as we have today.1 At today’s prices, this buildout would cost over $2.2 trillion, and of course, wind turbines only last 20-30 years.

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North Dakota, South Dakota, Nebraska, and Kansas would experience the most warming, with temperatures increasing by 1.4 to 1.8°F on average, while smaller warming effects would spread from Montana to Michigan, by 0.5 to 0.9°F.

Notably, nighttime temperatures would increase by more than daytime temperatures, with the mercury rising by 2 to 2.5°F (1.5°C) in the most affected portions of the country. The warming at night is most prevalent for wind because during the day, convection from the sun is the primary mechanism for mixing the heat in the air, but at night, that mixing is caused by the turbine blades spinning.

Implications of Wind Warming

Wind and solar advocates will likely argue that the warming caused by wind is not as bad as the warming caused by emissions because wind turbines neither generate new warming nor trap new heat in the atmosphere.

However, this argument misses the point. If the entire purpose of reducing greenhouse emissions is to mitigate the negative impacts on the environment, people, plants, and animals caused by a warming world, it does not make sense to incur the economic and environmental costs of warming using intermittent energy when other alternatives exist.

A 2017 study that attempted to quantify the costs of warming estimated that the U.S. would lose 1 percent of its GDP per year for every 1°C increase in temperature. If wind warming increases temperatures in the U.S. by 0.24 degrees C, then the annual cost of wind warming would be roughly $72-$75 billion per year when all the turbines were up and running in 2080, per the Harvard study, and smaller in the years leading up to it.

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It makes exceedingly little sense to spend $2.2 trillion building a power system that would guarantee that we incur tens of billions of dollars in damages each year from large, localized, and immediate wind-induced warming in exchange for temperature changes that are too small and too dispersed to be perceptible at the local level in most of our lifetimes.

After all, we should care just as much about the people living today as we do the people living in the future. According to the Harvard study, residents in the “wind farm region” would experience so much near-term warming from wind turbines that it would essentially require the entire world to decarbonize by 2080 for them to start coming out ahead from a temperature perspective, based on the study’s findings.

Conclusion

Wind and solar are often described as messianic technologies that will save the planet from increasing warming. While these sources do not emit greenhouse gases, they cause a greater and more immediate impact on regional temperatures by mixing air columns and through the solar heat island effect, although this impact is much smaller than wind-driven warming.

Policymakers should question the wisdom of spending $2.2 trillions building 1.3 million megawatts (MW) of wind turbine capacity (more when we consider they only last 20-30 years) for the privilege of causing more immediate, local warming than we hope to avert on a global scale in over 100 years by reducing emissions.

For our friends who are truly worried about the implications of a warmer world, this is a clear sign they should embrace nuclear and be gone with the wind.

New York Demands a Climate Sacrifice by the Wall Street Journal Journal

Rage Against the Data Center by

New York’s grid operator says the lights might go out this summer by

For years, the power sector has been running on a vibes-based fiction, one that said we could build a grid around intermittent resources and figure out reliability later.

When demand was flat and reserve margins were hefty, this was a convincing narrative for many, but the need for reliable power has a way of correcting markets that drift too far from physical reality.

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Nowhere is that correction more visible than in the PJM Interconnection queue.

Results in the first round of PJM’s reformed interconnection process are devastating for wind and solar, and the idea that these resources can reliably serve the electricity grid. By a wide margin, natural gas is now leading the queue and is beating wind and solar combined.

Alongside storage and nuclear, this underscores a simple truth: when reliability matters, markets gravitate toward firm, dispatchable resources—even when federal subsidies and state wind and solar mandates stack the deck against them.

And thanks in large part to the explosive growth of data centers, reliability matters again, and that means wind and solar should learn to code.

The Scope of the Devastation

The PJM interconnection queue is having a “Come to Jesus” moment. And when it comes to the electricity industry, reliable and dispatchable power is the savior.

After years of being a parking lot for intermittent wind and solar projects, the reformed interconnection queue process has resulted in a queue that is heavily skewed toward “firming” resources.

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As you can see, natural gas is leading the pack at 105,797 megawatts (MW), which by itself beats out wind and solar combined by nearly 4 to 1.

When coupling storage and nuclear in the mix—which are the next top resources in the queue and also meant to “firm” the grid for massive load growth expectations—that ratio jumps to nearly 7 to 1.

This is night and day from a mere few years ago, when intermittent projects made up the vast majority of interconnection queue submissions.

Compared to 2023, wind and solar project submissions are down 89 percent and 90 percent, respectively, while natural gas is up 1,810 percent, and nuclear went from 0 to 17,906 MW.

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This suggests what many of us have known all along: you can’t power a grid on hopes and wishes, and that’s exactly what wind and solar represent.

Surprisingly, even nuclear alone beats out standalone solar and wind separately. The nuclear total includes a fusion reactor that we will believe when we see it, but the same idea holds—PJM is in desperate need of reliable generation to meet massive load growth projections in the near future and to alleviate soaring capacity prices. As a result, it’s turning to resources that can actually achieve this end.

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Soaring Demand and Capacity Prices

Say what you want about data centers, but the change-up in PJM is largely due to load growth expectations driven by energy-intensive industries.

And this was a much-needed correction. The fact that markets are having trouble meeting this demand without burdening residential ratepayers with higher bills is more of a testament against the way we’ve been operating the grid for the past three decades, rather than a dig on data centers themselves. Historically, large-load users helped keep costs low.

This is a challenge that needs to be met, but it’s important to remember why it’s a challenge in the first place.

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After years of flat demand that allowed complacency to take over energy policy and dwindle the sizable dispatchable reserve margin on the grid, we’re now struggling to meet load growth expectations today that from the 1950s to early 2000s we managed just fine. Indeed, data centers and other large-load users have placed reliability back where it needs to be: at the top of the priority list.

PJM is finding out why it’s so important. Incoming data centers and other large-load industries need power 24/7. At the same time, the system has spent years (and is still) retiring dispatchable capacity and replacing it with resources that have limited contribution during peak conditions.

In a capacity market, when a gap between reliable generators and load growth becomes visible, prices increase. Therefore, rising capacity prices in PJM aren’t a mystery. They’re the direct result of less dispatchable supply, more inflexible demand, and resource additions that don’t carry equivalent reliability value.

The market isn’t confused. It’s reacting exactly the way it’s supposed to, despite market distortions that heavily favor intermittent, weather-based resources. This goes to show just how important thermal and dispatchable capacity is—that despite decades of unfavorable policies and regulations, they are still standing and refusing to go away.

The opposite is true for wind and solar. Just as soon as you level the playing field and load growth demands reliable generation, they fold under the pressure.

And there’s a very clear reason for this.

Effective Load Carrying Capacities

The market is responding to the fact that wind and solar experience declines in their capacity value as more MWs are added to the grid.

Perhaps there is room for wind and solar to be part of the energy mix at very low penetrations (which we are skeptical of), but certainly not for providing the bulk of power production on the grid. The reason is simple physics and mathematics, highlighted by decreasing marginal capacity values.

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We highlighted the diminishing returns of wind and solar in a pervious piece, More is Less with Wind and Solar.

Wind and solar capacity values fall as more of these resources are added to the grid because their output patterns are often correlated—the sun sets over an entire continent or concentrated wind turbines experience a wind drought—and they are non-dispatchable. As a result, adding more of the same variable resource reaches a point where the resource does not meaningfully contribute to reliability.

…This is reflected by diminishing capacity values for wind and solar in several major regional transmission operators (RTOs) in the country, which we detail below.

This is the case in every RTO in the country.

Falling capacity accreditation for wind and solar means these resources are increasingly unable to capture high capacity prices in capacity auctions. This is not a bug; it is a feature of how the capacity markets should work, rewarding resources with high reliability values while less reliable resources miss out on the action.

Conclusion

The truth is that the change in the interconnection queue in PJM is a symptom of a greater problem and an admission that the RTO was not prepared to handle surging load growth after years of flat demand and political pressure to prioritize intermittent generators over coal, natural gas, and nuclear generators.

After years of misplaced priorities and politicians being asleep at the wheel, market participants are now playing catch-up all at once, rushing to build more reliable natural gas, nuclear, and battery storage, and leaving wind and solar on the sidelines.

GE Vernova gas turbine backlog hits 100 GW as prices rise. Surging demand for reliable power creates a big need for natural gas.

GE Vernova’s gas turbine backlog reached 100 GW in the first quarter, up sharply from 83 GW at the end of 2025. Parks said the company shipped 25 gas turbines in the quarter, a 32% increase from the first quarter of 2025, with pricing rising faster than the inflation rate.

“We continue to be in that 10% to 20% growth in price on new bidding and winning activity today relative to where we were in the backlog in the fourth quarter of last year,” Strazik said later on the Wednesday call. “The dollar-per-kilowatt growth is going to be very healthy in the second quarter of this year.”

MISO capacity prices fall as new supply outpaces demand growth

Capacity prices fell sharply in the summer season — from $666.50/MW-day in all regions to $424.30/MW-day in MISO’s North and Central regions, $384.10/MW-day in Arkansas and Mississippi and $412.10/MW-day in Louisiana and Texas.

A recent Gallup poll found that Americans’ rating of the environment has reached a new all-time low, with 66 percent of respondents saying the environment is getting worse.

The only problem? The data show the exact opposite is happening.

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The Doors of Perception

According to Gallup, only 35 percent of Americans rate environmental quality as excellent or good, the lowest point since the survey began in 2001. In contrast, 20 percent now believe that environmental quality is bad, which is a new high.

According to Gallup, the decline is driven mostly by independents, whose rating has fallen by 10 points since last year. Gallup data shows Republicans are consistently the demographic that believes that the environment is good, and Democrats are the most likely to think the environment is bad.

Interestingly, views on whether the environment is getting better or worse are highly partisan based on who’s in office. Gallup survey data show that Democrats think the environment is getting better during Democratic presidential administrations, while Republicans are now more inclined to also view environmental quality through a partisan lens.

As you can see, 40-45 percent of Democrats thought the quality of the environment was getting better during Obama’s presidency. The same belief dropped to 10 percent during Trump’s first term before shooting back up near the 40s when Biden was in office. Now, in Trump’s second term, only 6 percent of Democrats hold the same view. Republicans show the same behavior but in opposite directions—as high as 60 percent of Republicans thought the environment was improving during Trump’s first term, dropping to as low as 30 under Biden and rising back up to the 60s in Trump’s second term.

It’s Getting Better All The Time

The problem with the above is that beliefs about the environment are largely detached from the actual data.

All measurable environmental quality metrics have shown consistent improvement over the last 25 years, regardless of which party controls the White House, and the trends are even starker when we examine the entirety of U.S. Environmental Protection Agency (EPA) air pollution data going back to 1970.

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The facts are that air quality in these United States has been getting better, not worse, for the last five decades, and emissions in the country have fallen dramatically. The data below highlights just how much.

Criteria Pollutant Trends

EPA data show massive drops in pollutants like nitrous oxides (NOx), sulfur dioxide (SO2), and small particulate matter (PM). EPA measures two types of particulate matter pollution, those 10 micrometers in diameter (PM10), and 2.5 micrometers in diameter (PM2.5)

NOx

The graph below shows NOx data going back to 1970 for the four major source categories: power plants, industrial fuels, highway vehicles, and non-highway vehicles, and the total U.S. emissions during this time.

EPA data show that power plant NOx emissions fell from 4.9 million tons in 1970 to 751,000 tons in 2024, a drop of 85 percent over this period. Total emissions fell by 74 percent.

It is worth noting that the graph above shows that the vast majority of these pollution reductions have occurred since around the year 2000, which coincides with the timeframe of the Gallup survey on environmental sentiment.

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SO2

Sulfur dioxide emissions have also fallen dramatically, with SO₂ emissions decreasing by about 95 percent since 1970, while power plant emissions have dropped by roughly 96 percent. Again, the data shows vast improvements since the year 2000.

PM 10 and PM 2.5

PM 10 emissions are largely the result of what the EPA considers “miscellaneous” sources. These include significant volumes of fugitive dust from roads, agriculture, and construction.

The sharp increase in the mid-1980s reflects EPA expanding the inventory to include these sources, rather than a real-world surge in emissions.

Interestingly, wildfires accounted for 770,000 tons of PM10 in 2024, which was 8 times more than the 94,000 tons emitted by power plants in that year. Overall, power plants accounted for 0.6 percent of U.S. PM 10 emissions.

It is a similar story for PM2.5, which is dominated by the miscellaneous category and, more recently, wildfire smoke.

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Carbon Monoxide

Carbon monoxide (CO) emissions have fallen by 78 percent since 1970, but power plant CO emissions have risen slightly over the same period. However, despite a slight rise since 1970, power plants accounted for less than 1 percent of total U.S. CO emissions in 2024, and the decline in emissions is linked pretty close with the main source: vehicles.

Ironically, rising CO emissions from power plants may be the result of adding more wind and solar to the grid.

EPA documents explain that CO emissions are largely a byproduct of incomplete combustion at natural gas plants, occurring most frequently during startup, shutdown, and low-load operation. As more wind and solar are added, gas plants are used more flexibly to balance the system, leading to more frequent cycling and longer periods in these operating modes, which increases CO formation.

Mercury

America has made tremendous progress in reducing mercury emissions from power plants. In fact, mercury emissions from U.S. coal plants have plummeted by 93.5 percent since 2008 (before the EPA’s Mercury and Air Toxics Standards were introduced in 2011 and implemented in 2015) while they continued to produce reliable, affordable electricity for the country.

Mercury emissions from U.S. power plants have fallen so much that they produce less mercury than small-scale mining operations in Africa, Asia, and South America, global cement production, and even global cremations, according to the United Nations’ data.

Why Have Emissions Fallen So Far?

Emissions have fallen steadily in the power sector due to pollution controls on power plants, the introduction of catalytic converters on cars and the use of low-sulfur gasoline, and other steps to reduce pollutants.

The graphs below, which use U.S. Energy Information Administration data, show that these pollution control technologies worked to reduce emissions, especially from coal plants, even as coal generation increased from 1990 to its peak in the mid-2000s.

Additionally, the substitution of natural gas, solar, and wind for coal in much of the country also accounted for reductions in coal-plant emissions.

Conclusion

While environmental issues often appear partisan in polls like Gallup’s, the underlying reality tells a different story. Americans of all political stripes can take some comfort in the fact that air quality has steadily improved over time, regardless of which party is in power. In fact, EPA data even suggests that indoor air quality is often worse than outdoor air quality.

This says something about the country as a whole.

Most Americans want a healthy environment—this much we can all agree on. Where the debate tends to break down is around policies that carry significant costs without clear, measurable benefits—such as proposals to transition the electric grid from fuel-based to weather-dependent generation.

So head outside, breathe easy—and if you found this perspective useful, hit like, share, and consider becoming a paid subscriber to help us keep climbing the Climate and Environment leaderboard.

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Pa. governor enters consent decree to keep 2 coal plants operating: Two coal-fired power plants in western Pennsylvania will be able to operate an additional four years after Gov. Josh Shapiro (D) struck a deal with their operators to meet federal wastewater standards.

Electric vehicle sales in California sputter “Sales of zero-emission vehicles in California slumped 40.2% in the first quarter of this year, compared with the first three months of 2025, according to figures released Tuesday by the California New Car Dealers Association. Registrations for ZEVs

Americans’ Rating of Environment Hits New Low. Americans’ views on the environment are quite partisan.

In this upcoming report, we argue that regulatory agencies like the Environmental Protection Agency (EPA) and utility regulators should be required to determine whether proposed power plant regulations or integrated resource plans (IRPs) will result in blackouts based on hourly reliability assessments using historical weather patterns, and to calculate the economic damages from those outages.

Importantly, our analysis offers guidance on how to do that, providing a process for modeling the reliability of proposed regulations or resource plans and calculating the cost of blackouts. The report should be out around June.

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Why Develop the Social Cost of Blackouts?

The EPA and utility commissions routinely employ externality cost estimates for carbon dioxide and other greenhouse gases (GHGs) using a metric called the Social Cost of Carbon (SCC). But these regulators completely ignore the negative externalities their rules or IRP determinations may cause by regulating reliable power plants off the grid or allowing them to be shuttered prematurely to reduce emissions.

This historically unbalanced focus on emissions-related externalities, while ignoring the possible externalities of blackouts, has led to declining reserve margins across the country as regulations and IRPs have favored intermittent wind and solar resources over dispatchable generators.

Furthermore, this practice has severely underestimated the cost of complying with these regulations by either not accounting for the blackouts they cause or building the required capacity to ensure reliability.

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These historical forces, and more recently surging demand from data centers, are partly responsible for how we got a North American Electric Reliability Corporation (NERC) Long-Term Reliability Assessment (LTRA) map that looks like a stock-market meltdown with half the nation at high risk of blackouts by 2030.

The growing risk of power outages resulting from supply shortages across America makes the Social Cost of Blackouts a relevant and necessary tool in the regulatory toolkit to ensure that reliable power plants are not undervalued.

Calculating Blackout Costs

Blackout costs are difficult to quantify because they depend on several factors, including the duration of the outage, the time at which it occurs, whether the outage was expected or unexpected, the weather or environmental conditions during the outage, and each customer’s individual electricity needs.

The difficulty is compounded when we consider that these factors can change widely from day to day.

For example, widespread blackouts on Thanksgiving would result in thousands of very unhappy (and hungry) residential customers, but the economic damages would be minimal because most non-essential businesses are closed for the holiday.

However, if a blackout occurs just 24 hours later, it would derail Black Friday, which is typically the largest single-day for retail sales in the country. Maybe these sales are lost, or maybe they simply happen at a later date, but the economic disruption is real and very tricky to quantify.

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In conducting our initial research for the project, we discovered a new tool called the Interruption Cost Estimate (ICE) calculator, developed by the Lawrence Berkeley National Laboratory (LBNL).

While ICE is not without limitations (it is generally good for quantifying the cost of outages no longer than 24 hours), this calculator allowed us to derive defensible estimates of the Social Cost of Blackouts for the Biden Administration’s Final Carbon Pollution Standards in the Midcontinent Independent System Operator (MISO) and Southwest Power Pool (SPP).

Southwest (Without) Power Pool

As we wrote in May of 2024, the EPA’s modeled SPP grid under the Final Carbon Rules was so irresponsibly dependent upon wind and solar generation that it would leave 5.2 million people in the dark if these resources perform as they have historically.

For example, the graph below shows the generation mix for SPP in each of the EPA test years (2028, 2030, 2035, 2040, 2045, 2050, and 2055). As you can see, EPA’s modeled SPP grid would need approximately 20 GW of wind or solar capacity at any given moment to meet projected peak demand, meaning SPP would not be able to weather an evening without wind.

To evaluate the reliability of this system, Always On scaled the hourly generation profiles of SPP—obtained from the U.S. Energy Information Administration’s Hourly Grid Monitor—so that the hourly peak would match EPA’s projected peak.

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Then, we used hourly capacity factors for wind and solar from 2019, 2020, 2021, 2022, and 2023 to assess whether the EPA’s estimated installed capacity would be able to serve demand for all hours if wind and solar operate as they have in the recent past.

We found blackouts everywhere.

The graph shows thirteen separate capacity shortfalls that would occur from February 7, 2040, through February 19, 2040, using 2021 hourly electricity demand profiles and wind and solar hourly generation data. The longest of these capacity shortfalls lasts for 41 straight hours. During this stretch, there are more hours with blackouts than without them.

The table shows the number of megawatt hours (MWhs) of unserved load in each of EPA’s model years in SPP for each historical comparison year. Based on 2021 demand and wind and solar production, there would be 8.3 million MWhs of unserved load across these seven model years.

Using the ICE calculator, we were able to translate these outages into economic costs of blackouts, using the worst-case results from the above table as our examples.

Using the ICE Calculator

As we alluded to before, the ICE calculator has limitations. Chief among them that it can only model blackouts of 24 hours or less. As a result, the ICE calculator wasn’t even able to handle the breadth of the blackouts in SPP because they were so massive.

However, we can model most of the blackouts using this tool, and the costs are enormous.

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The ICE calculator utilizes three reliability metrics reported by utility companies to calculate the cost of blackouts, such as the System Average Interruption Duration Index (SAIDI), the System Average Interruption Frequency Index (SAIFI), and the Customer Average Interruption Duration Index (CAIDI). SAIDI represents how many minutes of power outages per year the average customer experiences, SAIFI is the number of power outages the average customer experiences, and CAIDI is the average time it takes to restore power.

While utilities utilize these metrics to locate where system improvements are needed, we are using them here specifically to calculate the potential cost of future blackouts arising from inadequate generation portfolios.

It helps here that we only need to find two of these metrics, because they are related to each other by the following formula:

The first step for us is to convert the hourly shortfall data for each test year into two of these reliability metrics, SAIDI and CAIDI, which are the easiest to find given our data.

For SAIDI, we need to figure out the equivalent number of hours that went unserved for the average customer. We can do this by dividing the total annual MWhs of shortfalls by the average hourly load of the system. For CAIDI, we simply find the average length of every shortfall event in each test year.

From here, we can derive SAIFI by dividing SAIDI by CAIDI.

The Cost of SPP Blackouts

Using the ICE model, there are three interesting ways to examine the cost of blackouts: the total cost of the blackouts, the cost per MWh of unserved energy, and the cost of the blackout per avoided ton of carbon dioxide. The ICE model derives the first two, while for the third, we need to divide the total cost by the total avoided tons of carbon dioxide based on our modeling.

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The graph below shows the total cost of blackouts in SPP based on our modeling of EPA regulations.

As mentioned before, the SAIDI value is maxed out in the ICE calculator from 2040 to 2055. Due to customer growth, the total cost of the blackouts increases through 2055, starting at just over $11 billion in 2030 to over $53 billion in 2055. The cost per customer per MWh unserved, on the other hand, starts higher and drops as the blackouts get larger and longer because the model utilizes survey data that shows the most expensive MWhs to customers during blackouts are the early ones, and each incremental hour is less expensive than the one before it.

The implications of this are massive.

In one RTO alone, by severely underbuilding the grid and relying too much on wind and solar to meet peak demand, the EPA missed potentially $1.1 trillion in economic costs resulting from blackouts from 2030 to 2055 when extrapolating the data for years in between the test years. And once again, the ICE model wasn’t able to capture how bad the data for SPP truly was, so this value is even higher.

The graph below highlights the annual cost per ton of carbon dioxide averted from 2024 emission levels, which increases from $300 per ton in 2030 to $504 per ton in 2055.

Needless to say, the cost of avoiding carbon emissions far exceeds the cost of using fossil-fuel generation to reliably serve electricity demand.

Conclusion

This is just one example of how calculating the Social Cost of Blackouts can be useful for bringing reliability back to the forefront in ways that matter for energy policy.

Metrics like the social cost of carbon are arbitrary, incomplete, and uncertain. Blackouts have a very real and direct cost on society. And by not accounting for the reliability impact of generation mixes heavily dependent on intermittent and weather-based resources like wind and solar, resource planners and policymakers have been ignoring trillions of dollars arising from their proposals.

Energy policy has been careless for decades on this front, and we’re now starting to pay the price of those mistakes. Electricity prices are through the roof, and almost every grid in the country is struggling to make room for an energy-intensive data center industry despite having more capacity than ever before. The grid is supposed to be designed to best serve load growth while maintaining reliability at an affordable cost to society, and it has failed in this regard.

The issue, of course, is that the capacity we’ve been building (wind and solar) is next to worthless when it comes to reliability, and therefore it’s expensive. This is what happens when reliability considerations take a backseat to climate policies, and the Social Cost of Blackouts is meant to change that.

Our quest to the Top Ten in the Climate and Environment category continues apace. Thank you to everyone who has become a paid subscriber in the last month. You have helped us leapfrog Erin Brockovich, and Bill McKibben almost certainly has nightmares about us every night ;-)

Retail Electricity Price Trends and Drivers: Data Update−2026 Edition Checking out a few slides on the updated LNBL and Brattle retail price study.

Ratepayers could bear brunt of US utilities’ $1.4 trillion capex plans – report: Could???

Case Studies of the Economic Impacts of Power Interruptions and Damage to Electricity System Infrastructure from Extreme Events

In a November 8th, 2025, interview with the New York Times, Calvin Butler, the CEO of Exelon, one of the largest utilities in the United States, quipped that the best hack for lowering your electric bill is to turn off your lights.

The notion that Americans can save money on their power bills by simply consuming less electricity is pervasive among climate activists, organizations that push for wind, solar, and energy-efficiency/demand response mandates, and, of course, utility executives looking for ways to shift the blame for high costs back to the consumers for having the audacity to use electricity.

However, this energy efficiency messaging is, at best, outdated and, at worst, intentionally misleading.

What’s worse is that this message will become even more obsolete in the coming decades if we prioritize power plants with no or low fuel costs, such as wind, solar, battery storage systems, and nuclear power plants, because these energy sources effectively destroy the financial incentive to conserve electricity compared to coal and natural gas power plants.

To find out why, let us examine the fork in this particular socket.

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NextEra Energy Resources is descending upon my home county of Waupaca, Wisconsin, seeking to build a 300- to 375-megawatt (MW) solar facility called the Cloverleaf Solar Project. The project would be located on 1,500 acres near Clintonville, Wisconsin.

You’d be forgiven if you’ve never heard of Clintonville, or aren’t sure how to pronounce Waupaca (Wah-Pack-Ah), but today’s post will discuss how the expansion of solar into Central Wisconsin is emblematic of why Wisconsin electricity prices have gotten so expensive in the last decade.

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Rising Power Prices in the Dairyland

As we detailed in our Electricity Affordability in Wisconsin brief from Always On Energy Research, residents of America’s Dairyland have the second-fastest growth in electricity prices in the Midwest since 2001, outpacing the national average by 41 percent during this time period. As a result, electricity prices have more than doubled from 6.08 cents per kilowatt-hour (kWh) in 2001 to 12.72 cents per kWh in 2024.

These cost increases are driven by two main factors that will surprise exactly zero of our readers: premature coal plant retirements and utilities spending billions of dollars on wind, solar, battery, and natural gas facilities to replace them.

Wisconsin Utility Regulation: The Worst of Both Worlds

Unfortunately, Wisconsin has the worst of both worlds when it comes to monopoly utility regulation.

Customers have no option to choose their own provider, and there is no integrated resource planning process in Wisconsin, which means monopoly utilities like We Energies, Alliant Energy, and Xcel Energy can, and routinely do, shut down their resources without approval from the Wisconsin Public Service Commission (PSC).

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This means utilities can force ratepayers to pay for demolished assets for decades after they shut down, which is exactly what happened with the Pleasant Prairie coal facility in Southeastern Wisconsin.

With units placed into service in 1980 and 1985, Pleasant Prairie was a relatively young power plant when We Energies prematurely retired it in 2018 after the company had just spent millions on new emissions controls to comply with federal regulations.

Despite the closure, Wisconsinites will likely be forced to pay over $1 billion for the plant—$665 million reflecting the unamortized balance at retirement and more than $400 million in utility profits and financing costs—for a power plant that stopped operating in 2018 but will remain on customer bills through 2039.

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Other coal-fired plants, such as the Columbia Energy Center, Oak Creek, Edgewater, and Elm Road, are now slated for premature closure or conversion, despite producing some of the lowest-cost power in the state, and far less than the cost of new solar projects, like the Cloverleaf Project in Waupaca County.

The graph below shows that Columbia produced electricity for just $36 per megawatt-hour (MWh) in 2024, while the coal fleet as a whole produced electricity at an average of $57 per MWh. In comparison, we calculated the cost of new solar to be over $103 per MWh, using capital cost assumptions from the U.S. Energy Information Administration’s (EIA) Electricity Market Module (EMM).

Despite the fact that new wind and solar are much more expensive than existing coal and even new natural gas plants, S&P Global data shows Wisconsinites will also be forced to pay an additional $16.3 billion in the next four years to finance the construction of wind, solar, and battery storage facilities that are more expensive and less reliable than the coal plants they are meant to replace, including projects like Cloverleaf Solar.

The Cloverleaf Cost Conundrum

NextEra does not provide cost figures for electricity generated at its facility, and they did not respond to our inquiry about this topic. However, we were able to estimate them based on information on the Cloverleaf Project website. NextEra expects to spend $358 million on the 300 MW project, which pencils out to about $1,193 per kilowatt (kW) of installed capacity, which is slightly less than the EIA estimates.

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As a result, unsubsidized costs range from $70.90 to $108.90 per MWh, depending on the facility’s productivity over its lifetime. However, these costs rise to $114.8 per MWh and up to $179.5 per MWh when we include the cost of “firming” solar power with backup generation to ensure Wisconsin has electricity when the sun goes down.

Costs are driven in large part by the fact that Wisconsin is a suboptimal market for solar, with facilities statewide generating just 18.3 percent of their potential output in 2024, and monthly capacity factors in January and February reaching just 5.9 percent.

In short, building new solar won’t bring down electricity prices because even when using the most generous assumptions for solar, it is more expensive than new natural gas plants, and it is far more expensive than existing coal plants. These costs are even higher when we consider the firming cost of the resource, which renders projects like Cloverleaf solar utterly uneconomic.

The Beatings Will Continue

On Wednesday, April 1st, Wisconsin’s largest utility companies, WE Energies and Wisconsin Public Service (WPS), which are owned by the WEC Energy Group parent company, announced plans to raise residential bills by $22 per month and $16.50 per month, respectively, by 2028. The Milwaukee Journal Sentinel reports that this is the sixth rate increase since 2020.

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Despite the serious operational limitations of solar in Wisconsin, the Section 1: 8-K filing released by the utilities suggests that much of this rate hike will be malinvested into more solar, battery, wind, and natural gas peaking installations. This spending spree will go far to boost the companies’ corporate profits, which the company boasts have met or exceeded the top-end of its earnings guidance for 22 consecutive years.

We Energies and WPS customers will be on the hook for $12.6 billion in new solar, storage, and wind projects from 2026 to 2030.1

These solar and wind capital cost numbers are absolutely massive. Doing the math, this equates to $3,243 per kW of installed capacity for wind and $2,052 per kW for solar, which are much higher than EIA estimates of $1,582 per kW and $1,409 per kW, respectively.

These inflated capital cost values lead to high per-MWh costs, even when using generous assumptions for wind and solar capacity factors. The graph below shows that the WEC Group’s new unsubsidized solar facilities would cost $108.93 per MWh, and unsubsidized wind would cost $96.23 per MWh.

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In what universe does replacing the existing coal fleet, which generates power at costs between $36 and $57 per MWh, make any sense for Wisconsin families and businesses?

WEC Energy Group’s plan also includes spending $5.2 billion on 3,300 MW of combustion turbine capacity used for peaking events. That equates to $1,575 per kW, which is in line with current EIA estimates. However, it’s worth noting that these prices have risen by over 40 percent since the 2021 EIA Annual Energy Outlook was published.

All in all, the Badger state is in for a bad time for their electricity costs.

The Political Problem

The energy affordability problem in Wisconsin is bipartisan.

Democrats tend to want to decarbonize as quickly as possible, and they legitimately do not seem smart enough to understand that requiring utilities to spend billions of dollars building wind, solar, and battery storage facilities, and prematurely retiring depreciated, low-cost, reliable coal plants, is exactly what is driving massive corporate profits and raising electricity prices.

Republicans, for their part, have tended to take a hands-off approach to utility regulation under the mistaken belief that utilities are private companies and should be allowed to operate as they see fit.

But electric utilities are not private companies; they are monopolies with the exclusive right to sell power in their service territories, leaving customers with no recourse to lower their costs or improve their service.

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These approaches have led to rate increases in different ways. A story in WisPolitics found that Gov. Tony Evers’ picks for the PSC have approved $2.2 billion in utility rate increases since becoming a majority on the body, more than seven times what former Gov. Scott Walker’s nominees did over a similar period.

However, Republicans and the Walker Administration share some responsibility, too. When We Energies announced it would prematurely close the Pleasant Prairie plant, they pretty much shrugged their shoulders and let it happen.

Thankfully, there appears to be a growing number of conservative lawmakers who are interested in requiring utilities to sell, rather than shut down their existing coal plants and question the value of investments in unreliable wind and solar resources.

Conclusion

With its long winters and short days, solar is a suboptimal investment compared to other forms of electricity generation. As we demonstrated with the Cloverleaf project, it costs far more to generate electricity from solar than from existing resources or new natural gas plants, but it looks like a bargain compared to projects proposed by the WEC Energy Group.

Rather than allowing utilities to continue to stick it to ratepayers, Badger state policymakers need to give the PSC more oversight into utility retirement decisions, enact the Only Pay for What You Get act to limit utility profits on unreliable resources, and require utilities to sell their existing assets, rather than retire them, and give most of the money back to the ratepayers who funded the plants in the first place.

Recent Decade’s Power Outage Data Reveals the Increasing Vulnerability of U.S. Power Infrastructure

Scarcity Pricing White Paper: Value of Lost Load and Operating Reserve Demand Curve

Please take a second to check it out by clicking this YouTube link. We would like to crush the competition with respect to total views, and every click counts. Thank you for your attention to this matter.

On March 3rd, JPMorgan Chase released its 16th Annual Eye on the Market Energy Paper. This year’s report, written by Michael Cembalest, is titled “Fighting Words,” and it is a 98-page analysis with hundreds of graphs and charts on the state of the energy industry.

It spans most aspects of the energy industry, but as with all things energy, much of this year’s report centers on the impact of data centers on cost and reliability. Also of note are discussions on the cost of solar and storage, conventional fuels, small modular reactors (SMRs), electricity prices, and battery storage economics.

Here are the nine takeaways we found most interesting from the study, hereafter referred to as the JPMC report.

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1. The Data Center Price Debate: A PJM Deep Dive

Data center impacts on customer costs continue to dominate the headlines for electricity affordability. The JPCM report notes:

The PJM region (data center alley: VA, PA, MD, OH) has 67 GW of existing and planned data center capacity, the largest cluster in the U.S. PJM has attracted attention due to spikes in its capacity payments, which are “insurance premiums” paid to generators to commit future supply or commit to demand response reductions during peak demand. Without the cap, the recent PJM auction would have cleared at $530 per MW per day.

While capacity payments take place in wholesale markets, they’re partially flowing through to retail power prices in MD and NJ. Factors driving the spike in PJM capacity payments include retirement of thermal assets, data centers and declines in capacity accreditation for solar and storage.

The reductions in capacity accreditation for solar and storage were overdue, and the recent increase in accreditation for onshore wind seems risky to us, as MISO, which, in fairness, has much more wind capacity than PJM, has the capacity value in the mid-teens.

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On a final PJM note, Cembalest seems to think data centers could end the electricity “deregulation” experiment. “Last point: some utilities within PJM are questioning whether re-regulation would be the better option (Exelon, First Energy, PPL, and PSEG); I agree with them.”

2. Data Centers Are Likely Causing Nighttime Load Growth

The JPMC report provides evidence that data centers are materially increasing electricity demand at night, which also happens to be the period when the sun doesn’t shine.

Nighttime loads have increased in Virginia and ERCOT since 2023. Nighttime loads are less influenced by industrial production or population. The increase in nighttime loads in data-center-heavy areas such as the Northern Virginia Dominion Zone and ERCOT suggests these facilities are driving evening demand, as JPMC notes, electric vehicles are not drawing enough power to be significant drivers of demand yet.

Cembalest writes “Nighttime load can be viewed as positive as it represents consistent load that allows utilities to monetize capital deployed assets and does not put additional strain during peak hours; but it’s another sign of rising data center demand.”

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3. Specialized Data Center Power Rates Can’t Afford Solar and Storage

The JPMC report notes seven states have passed or proposed measures to apply higher electricity rates to data centers to account for price impacts on generation, transmission, and distribution costs, and require mandatory participation in curtailment programs under certain conditions.

Despite these efforts, these higher data center electricity rates may not be high enough to completely offset their costs and insulate other ratepayers. Wood Mackenzie published a 2025 report concluding that new specialized rates for data centers may not be high enough to cover the costs of the new generation.

The graph below shows base electricity costs and specialized data center rates from various electric utilities, compared with the cost of new generation for combined-cycle natural gas and solar plus battery storage.

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As you can see, some of the specialized rates imposed by various utilities would be able to pay for a combined cycle gas plant, but none of them are high enough to pay for a solar plus battery storage facility.

This is particularly true because solar power purchase agreement (PPA) costs keep rising. The JPMC report notes that solar PPA costs, which are subsidized, are over $60 per MWh, a stunning increase from the sub-$30 per MWh deals that were being signed in 2019 and 2020.

It is increasingly looking like the rush to build solar and storage in the United States may go down as one of the largest misallocations of capital in our nation’s history. Data centers are increasing power demand at night, when solar and storage simply can’t do the job, and they are more expensive than dispatchable, non-energy duration-limited alternatives. We’ll be writing more about this dynamic in the near future.

4. The People Want Lots of Gas Turbines

Demand for gas turbines now exceeds the current global production capacity through 2030. After years of soft demand for natural gas turbines, it appears gas is back in a big way, which is unsurprising given the cost of gas compared to solar and storage.

Cembalest writes, “Three companies each have 20 to 25 percent of the global turbine market share: GE Vernova, Siemens, and Mitsubishi, and each is planning to expand production. Mitsubishi plans to double production capacity within two years; GE Vernova will ramp annual output from 16 GW in 2023/2024 to 22 GW later this year and to 26 GW by mid-2028; and Siemens Energy is investing $1 billion in US manufacturing, lifting its large turbine production capacity by ~20 percent.”

It remains unclear if this will be enough to clear backlogs as demand is simultaneously increasing.

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5. Nameplate Capacity is Not Always Reliable Capacity

Electricity demand rose 2-4 percent annually from 1950 through 2006. While grid planners managed to keep pace with this increase, this was a time when fuel-based resources made up a majority of all resource additions.

Unfortunately, this isn’t the case anymore. Even though the U.S. is building more new capacity annually than ever before, it’s not equating to reliable, firm capacity because new capacity builds are increasingly made up of intermittent wind and solar resources, while coal, natural gas, and nuclear additions have fallen to roughly 10 percent of new additions.

As Cembalest notes:

Whether the same pace can be maintained today is another question, particularly given shortages of skilled energy labor, shortages of transformers, breakers and other equipment and tariffs on grid equipment which do not benefit from the kind of exclusions granted to semiconductors and computers. As shown in the second chart, new US power capacity looks like it’s surging but is a lot more gradual after adjusting for reliability and intermittency (i.e., derating of solar and wind). In other words, not all megawatts are created equal.

We described the same trend in a recent piece, Watt, Me Worry?, where we add-on the fact that not only are reliable generators making up less of the share of new capacity additions, but that these additions aren’t keeping up with retirements. The result is that “the U.S. is now at pre-2005 levels of firm capacity on the grid at a time when electricity demand is projected to have the largest increases in over a decade due to data center and AI growth and electrification efforts.”

6. The Economics of Small Modular Reactors (SMR)

There is plenty of optimism for SMR technologies to mature into affordable options for the grid, and investors continue to express this optimism with their wallets. SMR stocks have stabilized and annual venture funding remains high.

However, as Cembalest notes, investor optimism doesn’t mean cost-effective, and “burden of proof for economic viability still lay with the SMR industry.”

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We stress the fact that any decarbonization campaign is an expensive one, whether using renewable or nuclear technologies. In the case of nuclear, this is because of the incredibly high up-front capital cost to build nuclear power plants.

As noted in the report, “A 2025 paper from the former chair of the US Nuclear Regulatory Commission reviewed four SMR types and estimated SMR levelized costs of $200 to $400 per MWh,” and that these surpass that of Light Water Reactors (LWRs) due to diseconomies of scale. Cembalest includes a Tennessee Valley Authority (TVA) analysis of a “first of its kind SMR,” resulting in a price of $196 per MWh—over 50% higher than Cembalest’s upper limit of what he considers “affordable” of $130 per MWh.

7. Blue States High Rates (And Others)

Cembalest also describes several factors that are correlated with higher electricity prices, including the fact that “Democratic states have higher power prices.” Our readers will know that we have noted the same thing.

The remaining four factors include:

• Deregulated states have higher prices than regulated states, which surpassed regulated states in 2022.

• States with more nuclear and hydro have lower prices.

• Wealthier regions have higher prices.

• Regions that rank low in business friendliness have higher prices.

8. Correcting EMBER’s Baseload Solar Analysis

Our readers will remember that Ember, a pro-wind and solar think tank, published an analysis last year claiming that “baseload” solar was now competitive globally with other forms of generation.

Cembalest is very direct in his criticism of EMBER’s report, concluding that “our analysis mostly rejects EMBER’s thesis and finds that their report understates the economic tradeoffs of deeply decarbonized solar + storage systems in cities like Las Vegas.”

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Cembalest notes: “On this kind of topic, stick to peer-reviewed pieces in publications like Joule. EMBER’s article is more a reflection of the world the authors want to exist rather than the world as it really is.”

We actually spoke with Cembalest and his team about Ember’s analysis after we published our article, The “Baseload” Solar Beatdown and our findings were very much aligned, with JMP estimating the cost of 90 percent solar 10 percent gas around $210 per MWh, compared to our estimate of $193 per MWh.

On a final note, the JPMC report examines what would have to happen for solar and storage costs to actually fall below natural gas. Here’s what they found:

What would it take for the unsubsidized cost curve to be flatter, implying a more even economic tradeoff between an all-gas system and the max penetration solar+storage system? Something like this: gas prices rise to $8 per mmbtu, AND solar capital and operating costs fall by 70%, AND 4-hour storage capital costs fall by 70%. While learning curves have been steep, $335 per kW for solar and $68 per kWh for storage seem a long way off, at least in the US. The impact of US tariffs raises the uncertainty further.

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9. ERCOT Battery Arbitrage Revenues Fall

ERCOT’s batteries are starting to resemble the Donner Party—more capacity is flooding the market and cannibalizing the buy-low/sell-high spreads that made storage profitable in the first place.

As the JPMC report notes: “2025 was a bad year for battery revenues. The reason: 9 GW of new battery capacity in ERCOT saturated Ancillary Services and pushed storage into diurnal energy market competition, compressing spreads across the grid and increasing storage capacity by 70x since 2020.”

Falling arbitrage revenue could eventually reduce the incentive for new entrants to the market, and leave the ERCOT region short of juice when it is needed most.

As we have noted previously, ERCOT is in a precarious reliability situation because the system has added no dispatchable resources, on net, since 2004, largely because subsidized wind and solar have driven down wholesale power prices to the point where natural gas investments don’t pencil out.

Battery storage capacity in ERCOT has skyrocketed, from virtually no storage in 2021 to over 12,000 megawatts in 2025. But there is a problem: solar and storage do a pretty good job of meeting summer peak demand, but short-duration storage is entirely unequipped to handle winter storms.

Texas continues to gamble with its grid.

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Conclusion

There is a lot to digest in the report, but there is no doubt that data centers have entirely reshaped the contours of the energy debate in just 18 months. Gone is the primary focus on decarbonization, and back in vogue is the need for reliable, dispatchable power at a price people and industries can afford.

Let’s hope this trend sticks around.

In Executive Order, Ayotte Reiterates Commitment to ‘Advanced Nuclear’

We notched a nice shoutout from the Ayotte administration in New Hampshire this week when they cited our report as the basis of their support for nuclear power:

In her State of the State address in February, Ayotte billed new nuclear generation as a forward-looking way to address the high energy costs faced by New Hampshire residents. New Hampshire is not a stranger to nuclear power: More than half of the energy generated in the state already comes from Seabrook Station.

Thanks to Seabrook, New Hampshire already generates more power than it consumes. In her executive order, Ayotte writes that increasing the share of nuclear power on the regional grid would lower rates more effectively than increasing reliance on renewable energy sources.

According to a spokesperson for the governor’s office, that conclusion is based on a 2026 report by consultant Always On Energy Research, released by a group of New England free market think tanks including the Josiah Bartlett Center for Public Policy, Americans for Prosperity Foundation, the Maine Policy Institute, and others.

The report concludes that increasing generation with a mixture of nuclear and gas generation would ultimately reduce costs for ratepayers.

The Cost of Continued Operation of Culley Unit 2 and Schahfer Units 17-18 Under Federal Power Act Orders: Synapse Energy Economics conducted a study on the cost of keeping two Indiana power plants open. Their numbers appear to rely on high fuel cost estimates that are not supported by S&P Global delivered fuel cost data.

Unpacking the Cost of 202(c) Orders: Facility-Specific Cost Estimates and Methodological Approach

Left’s War On Cheap Energy And Data Centers Threatens AI Race With China, our friend at Nuclear Barbarians does a very nice job on Michael Shellenberger’s show.

Because the leaderboard is mostly driven by revenue, upgrading your subscription to paid or premium will bring us one step closer to deposing Bill McKibben from the top of the rankings.

Thank you for being a loyal Energy Bad Boys subscriber. Now, for the rest of the show.

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In a startling report submitted to the Colorado Public Utilities Commission, Xcel Energy admitted that it will likely be in a “capacity deficit”—which is a nice way of saying its system does not meet its reliability requirements—from now until at least 2028, unless it keeps its Colorado coal plants open.

One almost feels bad for the predicament the company finds itself in, and we may even have a brief glimmer of admiration for its willingness to bluntly highlight the issue, but then we remember:

• In 2018, Xcel became the first investor-owned utility to declare its self-imposed environmental, social, governance (ESG) goal of making its system carbon-free by 2050;

• It has a history of giving thousands of dollars to climate groups like Fresh Energy in Minnesota and Western Resource Advocates in Colorado, and working with them to push for the closure of its coal plants and decarbonization mandates, and;

• Xcel lobbied in favor of the carbon-free electricity mandates passed in Minnesota and Colorado.

Furthermore, when we look at Xcel’s most recent investor presentation, we see that the company is practically giddy about all the ratepayer money it will spend on wind, solar, and batteries, which will increase its rate base and, in turn, its corporate profits.

In short, Xcel Energy is not a victim, nor is it brave for finally bringing attention to the need to maintain our existing generating resources—a reality that we, along with the Independence Institute, have been highlighting for nearly a decade. In short, Xcel is simply reaping the entirely foreseeable consequences of its own self-serving actions.

Let’s look at the reliability hole Xcel currently finds itself in, and disassemble Xcel’s lip service to reliability and affordability in its most recent investor presentation with a focus on the Centennial State.

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The Comanche Report

On March 2, Xcel Energy filed “The Comanche Report” with the Colorado Public Utilities Commission (PUC), where the company highlighted the severe resource adequacy deficit it currently finds itself in and the need to delay planned retirements for its coal units.

Specifically, Xcel noted the following:

[T]he Company’s near-term (i.e., 2026 and 2027) resource adequacy position is negative, 2028 is challenged, and these years present significant operational challenges even with Comanche 2 extended through the end of 2026. This report will discuss the limited incremental options for adding capacity resources that are needed. When the June Application is filed, swift action will be needed to shore up power needs for our customers in the near and intermediate terms. Difficult decisions about extending baseload units may be needed and additive transmission needs are likely part of solutioning these issues, as reliability of the system—in addition to the safety and affordability of such—remain the paramount goals of the Company and should be for Colorado as well.

Further into the report, it states that, “Near-term, the most likely capacity solutions are continued extensions of existing units—namely, Comanche Unit 2 and, to a lesser extent, the Hayden units.” Additionally, regarding repairing and restarting Comanche Unit 3, Xcel found “that the incremental cost to replacing Comanche Unit 3 would be magnitudes more expensive for customers than” restarting the facility, and that “there are no reasonable alternatives to returning Comanche Unit 3 to service.”

While this is true, it’s also true that accelerating the retirement date of Comanche Unit 3 from 2040 to 2030 is also more expensive for Colorado ratepayers, as we highlighted in our 2023 report in Colorado:

The accelerated retirement of Comanche 3–from 2040 to 2030–increased the cost of the Polis Plan by $8 billion alone, as the retired coal capacity needs to be replaced with wind, solar, and battery storage 10 years earlier than originally planned. The cost increase occurs because it accelerates the timeline in which investments must be made to replace the plant, which earn a rate of return for the utility paid for by ratepayers.

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Xcel advocating to keep coal plants online may seem shocking to those who know about Xcel’s “Steel for Fuel” initiative, which is the company’s motto for the strategy of building more fixed-cost generators like wind and solar (steel) to replace and displace thermal resources like coal and natural gas. The “Steel for Fuel” initiative was described in a 2017 Utility Dive article:

Xcel calls it “steel for fuel” — swapping out fossil generation for fuel-free wind and solar. At today’s prices, “everybody benefits,” Fowke said. Consumers get lower-cost energy and Xcel can earn a rate of return for building wind projects.

Unfortunately, only Xcel seems to have benefited, as consumers have been stuck with incredibly high-cost energy while Xcel's profits have exploded in recent years.

So, before anyone feels sorry for Xcel, or for those who may think it is the victim of misguided energy policies at the state and federal level (which are often misguided), understand that Xcel’s reliability crisis is a disaster of Xcel’s own making and the result of its own internal initiatives.

Xcel’s Self-Imposed Resource Adequacy Problems

Xcel’s reliability issues are self-inflicted wounds stemming from years of pursuing a 100 percent carbon-free electricity grid, which necessitated the closing of reliable generators like coal plants that the company now wants to delay.

Let’s look back in time to when Xcel became the first utility to commit to 100 percent carbon-free electricity in December 2018. At the time, Xcel’s environmental policy manager, Nick Martin, explained, “As the economics of clean energy have improved, it became clearer that we could meet more aggressive goals without sacrificing affordability or reliability for our customers.”

The Comanche Report has determined that this was incorrect.

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Since then, Xcel has consistently accelerated its plan to exit from coal and build new wind and solar facilities, and publicly supported clean energy legislation in multiple states.

In Colorado, specifically, House Bill 19-1261—also known as the Climate Action Plan—and Senate Bill 19-236 were signed into law by Colorado Governor Jared Polis on May 30, 2019, which collectively set out targets for Colorado to reduce its greenhouse gas emissions by 80 percent by 2030 and made it mandatory for electric utilities like Xcel to file clean energy plans to pursue a clean energy transition.

Xcel supported these initiatives, and when it filed its Clean Energy Plan in 2021, it explained that these policies “established a pathway and guidance for large regulated utilities to achieve the same goals we announced using Colorado’s ERP process.”

When Xcel’s Clean Energy Plan was eventually passed in 2022, it had accelerated the retirement of several coal facilities, including Comanche Unit 3, from 2070 to 2030—40 years earlier than scheduled and only 20 years after being placed into service.

Xcel noted at the time that it would also seek to “add ‘always available’ power sources to help back up wind and solar and maintain grid stability and reliability,” but it severely underestimated the implications of the policies it advocated for and supported. Every time Xcel sought new natural gas plants in the state, Colorado policymakers, regulators, and environmental groups would push instead for more wind, solar, and storage, arguing that natural gas would be sunk costs given the state’s emissions-reduction mandates.

This wasn’t just the strategy in Colorado. Xcel supported clean legislation in Minnesota and coal retirements in New Mexico and Texas, as well. In fact, a 2022 investor’s new release from Xcel noted the following:

Retiring coal generation while continuing to add reliable and affordable clean energy sources are key to Xcel Energy’s strategy in the eight states it serves.

To summarize: Xcel not only supported legislative efforts to close down coal power plants and build unreliable generators, but its own company goal of 100 percent carbon-free preceded them. And now, because of these efforts spearheaded by Xcel itself, reliability has been undermined in Colorado to the point that the same company is noting how critical these coal assets are for reliability.

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No Scenario Meets Reliability Standards

In the Comanche Report, Xcel analyzed reliability for several scenarios: one where it didn’t have Comanche units 2 and 3, a baseline scenario that extends Unit 2 through the end of 2026 and repairs Unit 3 in 2026, and scenarios A—D that have different extensions for the Comanche units and that include other small retirement delays and additions.

Shockingly, as shown in the figure below, no scenario maintained reliability above the industry standard of .1 Loss of Load Expectation (LOLE), which simply means that the utility could expect a loss of load one day over 10 years. As the company notes:

“Looking closely at the Company’s loss of load probability analyses, the various sensitivities indicate substantial risk in the next two years. Under all analyzed scenarios, the Company’s loss of load probability exceeds the planning standard of less than 0.1. In some cases, the loss of load probability is over 10 times greater than planning best practices.”

This isn’t a surprise to many of us, but it might be to those who believed Xcel when it said it could reliably and affordably pursue an energy transition to reduce emissions. As stated in its Clean Energy Plan in 2021:

After many years of technical and system advancements, we are able to confidently present for consideration by the Colorado Public Utilities Commission (“Commission”) a plan that would achieve by 2030 an estimated 85 percent reduction in carbon dioxide emissions from 2005 levels and deliver nearly 80 percent of our customers’ consumed energy from renewable resources. What makes this plan even more extraordinary is it accomplishes these objectives without compromising the Company’s longstanding focus on reliability and affordability.

Even though Xcel failed in maintaining reliability and affordability for its customers, it succeeded in growing its profits for shareholders.

All About that (Rate) Base

Xcel’s investor presentation conveys an entirely different tone than the somber Comanche Report. This tone can be most aptly illustrated by the image below.

Over the years, Colorado’s energy policy has shaped the assets in Xcel’s rate base. Based on S&P Global data, spending on generation, transmission, and distribution has surged nearly threefold, from $4.8 billion in 2009 to $13.6 billion in 2024.

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This figure is roughly commensurate with the $12.5 billion estimate reported by the Colorado Public Service Commission.

The timeline below shows major capital expenditures in the generation category by plant and cost. The increases in 2010 can be attributed to the addition of the Comanche 3 coal facility. Xcel also acquired two natural gas plants from Calpine in the early 2010s and converted the Cherokee coal plant to natural gas. The rate base increased again in 2018 when the Rush Creek Wind facility came online, and again in 2020 with the addition of the Cheyenne Ridge Wind facility.

Looking forward, Xcel is planning to spend huge sums on solar, wind, battery storage, and transmission lines in accordance with the policies it helped create.

From 2025 through 2028, Xcel is projected to build 901 MW of solar, 1,550 MW of wind, 600 MW of battery storage, and just 600 MW of new natural gas in its Public Service Company of Colorado territory, shown below as PSCo.

These malinvestments will lead to substantial growth in Xcel’s rate base.

Slide 62 from Xcel’s investor presentation shows the company’s rate base will increase by $17.6 billion in the next five years, as the company spends $4.9 billion on distribution upgrades, $4.65 billion on transmission upgrades, including its Colorado Power Pathway project, $2.2 billion on renewables, and $1.79 billion on “electric generation,” which we are told is a euphemism for new natural gas plants.

A recent webinar by the Colorado Public Utilities Commission shows a range of potential rate outcomes from Xcel’s spending plans. Rate hikes could be modest if load growth is substantial, but if load growth comes in below the forecast, Xcel’s own rate forecasts suggest this buildout could cause residential electricity prices to skyrocket by 55 percent in 2029, compared to 2024 levels.

The beatings will continue until policies improve.

Unfortunately, the people of Colorado are living H. L. Mencken’s quip about governance: “Democracy is the theory that the common people know what they want, and deserve to get it good and hard.” Colorado voters are reaping the consequences of the energy policies their elected officials enacted, with Xcel’s help.

Conclusion

Xcel Energy’s current reliability dilemma is a self-inflicted wound from decades of self-serving policies.

Perhaps Xcel thought they could feed the crocodiles by funding green advocacy groups and lobbying for carbon-free mandates, shut down their coal plants, and then cash in on new natural gas plants as the company’s reserve margins dwindled downward.

However, the new gas plants were blocked by the very interest groups Xcel helped cultivate, and now the company will be lucky to make it through the next few years without blackouts. If there are blackouts, there will be backlash, and Xcel will deserve every bit of it.

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Barclays Sounds the Alarm on Renewable Energy by

US planning first new coal power plant since 2013 in Alaska

Powering Intelligence 2026

On Tuesday, March 10th, an EF-1 tornado destroyed the Dunns Bridge Solar I and II facilities owned by the Northern Indiana Public Service Company (NIPSCO). The facilities, located outside of Wheatfield, Indiana, had 2.4 million solar panels, totaling 700 megawatts (MW) of power capacity, and reportedly cost $1 billion to construct—a little over $1,400 per kilowatt (kW).

NIPSCO issued the following statement in the aftermath:

On the evening of March 10, while actively monitoring severe weather and responding to storm‑related outages across our service area, NIPSCO became aware of damage to its Dunns Bridge I and Dunns Bridge II solar facilities in Starke and Jasper counties. Our team was tracking the storm in real time and moved in to assess conditions and respond as soon as it was safe to do so. Debris from the damage could have been displaced, and we are working to safely secure the area, assess the damage and proactively communicate with the community.

We recognize there may be questions and concerns about potential environmental impacts related to the damage at the solar farm. Solar panel leaching concerns have been thoroughly evaluated in industry-leading research, which shows that the risk is extremely low. Overall, the available evidence demonstrates that both crystalline silicon and thin-film PV (i.e., photovoltaic) modules do not pose a meaningful risk of environmental or human exposure from leaching, even when damaged.

The Chief Deputy of Jasper County Sheriff’s Department, Brandon Napier, noted, “Just the path of the tornado that came through, we have several large solar fields to the east of the town here it went right through the solar field and just ripped a lot of them out.”

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While the solar panels were damaged by the tornado, we are not aware of any reports of damage at the nearby R.M. Schahfer Generating Station, a 950 MW coal facility that NIPSCO was planning to retire at the end of 2025. However, it is still running thanks to a 202(C) order issued by the U.S. Department of Energy requiring the plant to continue operations. Click on the map below to explore the custom Google Map we made this week of the facilities.

This week, we wanted to take the opportunity to explore more about NIPSCO and share some data with our readers, especially given our recent research in the state.

This article will explore the cost of the destroyed solar facility compared to the nearby R.M. Schahfer Plant, and explore how energy costs have changed in the NIPSCO service territory in response to changes in the company’s generation fleet, using some cool data from S&P Global.

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It’s kind of a meandering exploration, but one of the things we value most about Substack and our readers is our ability to explore new ideas and see the feedback you all give. Thanks for being part of it.

Implications of the Destruction

According to S&P Global, the Dunns Bridge solar projects were built to “support Northern Indiana Public Service’s goal of becoming coal-free by 2028, reducing carbon emissions by more than 90 percent by 2030, compared to a 2005 baseline, according to the utility.”

The situation begs several questions:

• If climate change is going to make the weather more extreme, how does it make any sense to shut down coal plants and build energy generation facilities, like solar, that are destroyed by extreme weather?

• Are the company’s coal-free and emissions reduction goals increasing the company’s exposure to costs associated with weather events, and why should ratepayers be saddled with these additional costs?

• Was there any damage to the R.M. Schahfer coal plant or the onsite battery storage facility at Dunns Bridge?

• What type of insurance policy is in place for the solar facility, and what deductible would the company be required to pay, if any?

• What liability, if any, does the company have for the cleanup of the site and surrounding areas?

• How is any of this in the best interests of ratepayers?

We reached out to NIPSCO via their “24-hour” media hotline, asking for this information, but they did not respond to our inquiry at the time of publication, and we sincerely doubt they will.

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However, these are questions the company should have to answer in front of the Indiana Utility Regulatory Commission on March 24th at its scheduled hearing on energy affordability. They can dodge our questions, but they had better come clean to the regulators.

The Cost of Tornado-Truncated Solar Facility

Let’s be incredibly uncharitable and look at the anticipated levelized cost of energy (LCOE) of the solar facility over its projected 25-year useful lifetime, and its actual, tornado-truncated lifetime.

Dunns Bridge I began generating power in June of 2023, producing a total of 1.3 million megawatt hours (MWh) up until December of 2025, the most recent month for which data are available. Dunns Bridge II began generating power in January of 2025, and through December, it produced 812,439 MW of power, which is good for a 21.3 percent capacity factor.

We calculated the LCOE over two time periods: a 25-year lifecycle, a standard assumption in the industry, and a 2-year lifecycle to account for the facility being destroyed very early in its lifecycle. The results are about what we would expect. Our estimated subsidized costs over 25 years are approximately equal to S&P Global’s reported PPA cost for the facilities, including subsidies.

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Because the LCOE is like calculating the cost of driving your car over the number of miles driven, if your car dies after two years when you expected to drive it for 10, the cost per mile obviously increases. This is why the cost of electricity from the Dunns Bridge I & II facilities skyrockets in this analysis, reaching a subsidized cost of $289.61 per MWh, and an unsubsidized cost of $405.09 per MWh.

Is this a fair comparison? Probably not, because the solar facility was almost certainly insured and will likely be rebuilt after the site is remediated. The question is: how much are the cleanup and replacement costs, and what is the insurance deductible for the damaged facility, and who has to pay them?

It’s one thing to have an old roof on your house destroyed by a hailstorm (score), because you get a new roof for a fraction of the true replacement cost. But it’s another thing entirely to have a brand-new roof destroyed, because then you have the privilege of paying the deductible just to get your new roof back.

That’s potentially where NIPSCO’s ratepayers could end up sitting.

The Cost of the Nearby Coal Plant

In our upcoming LCOE study for Reliable Energy Inc. in Indiana, we found that the R.M. Schahfer plant was the most expensive coal plant in the state, due primarily to very high delivered fuel costs at the plant ($50 per MWh).

However, the December 2025 data from S&P Global, the most recent available, show the delivered fuel cost was about $27 per MWh, which substantially improves the economics of the plant, although this could possibly be the result of the company assuming the plant would retire at the end of the year, rather than being required to stay open.

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At $70 per MWh, the Schahfer plant is competitive with subsidized solar over a 25-year lifespan, cheaper than the unsubsidized cost over 25 years, and a bargain compared with our admittedly uncharitable comparison to the facility’s actual 2-year lifespan.

Of course, this analysis does not even account for backup power or other hidden costs associated with accommodating the solar facilities. If we did, the Schahfer plant would be the clear winner, even when compared to the subsidized cost of solar panels.

NIPSCO’s Changing Generation Profile

NIPSCO’s Dunns Bridge solar facilities are part of a larger trend away from coal-fired power generation toward natural gas, MISO market purchases, and increasingly, wind and solar ownership or power purchase agreements (PPAs).

This trend has coincided with a massive increase in the utilities’ estimated rate base. Data from S&P Global show NIPSCO’s rate base has more than doubled since 2016. You’ll notice that the rate base was essentially flat from 2000 to 2010 in non-inflation-adjusted terms. This is because electric companies are supposed to see their rate bases stabilize as their assets depreciate over time.

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The upward trend in rate base growth led to higher rates. Unfortunately, we are still compiling our database of historical utility rates, so we only have data going back to 2012. During this period, NIPSCO’s All-Sectors electricity rates increased by 38 percent.

It’s also interesting to look at what’s causing the rate base growth. In the mid 2000s and 2010s, the growth in NIPSCO’s spending was driven by generation spending. However, transmission and distribution spending began to increase around 2018, and generation spending fell in 2021, but rebounded slightly in 2024.

This graph supports some of the claims made in the Lawrence Berkeley National Laboratory (LBNL) study, which suggested that transmission and distribution, not generation, charges have increased electricity prices since 2020. However, it’s also worth noting that the graph above suggests the LBNL study may be missing significant increases in generation costs that occurred prior to 2020.

A Note On Cleanup and Contamination Concerns, Our Two Cents

Photos of the broken panels have stoked fears on social media about potential environmental damage from toxic chemicals leaching out of the shattered panels into the soil and local groundwater supplies.

For our part, we would encourage those in the surrounding areas not to worry too much about chemicals leaching from the panels into the soil or water. Photovoltaic panels are made mostly of glass, and the small amounts of toxic materials, such as lead used in soldering, are not a significant concern because they are present in small quantities and there is probably no realistic exposure pathway for humans.

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In this regard, it’s important to remember that it’s the dose that makes the poison. Taking too much Tylenol will kill you; a small amount will not.

While we are not overly worried about chemicals leaching from the panels, we are concerned about the glass. Glass is not generally considered toxic, but broken glass scattered across neighboring properties is still a problem. The storm likely blew debris well beyond the solar site, which could create issues for nearby farmers, especially if they are growing root crops.

Anecdotally, we’ve heard that large potato buyers won’t purchase potatoes from growers located within a mile of a glass recycling facility for precisely this reason. In other words, the real concern here isn’t chemical contamination, it’s debris.

NIPSCO should absolutely be on the hook for the cost of cleaning up the mess their solar panels created, but we also want to give people nearby some peace of mind that it’s not likely that this incident is posing a risk to their health.

Conclusion

There are lots of things that break when they get hit by a tornado, but our power plants shouldn’t be one of them.

The demise of the Dunns Bridge I & II solar facilities by one of the weakest classifications of tornado should be a nudge to Indiana policymakers and utility regulators that shutting down dispatchable thermal plants in favor of flimsier wind and solar facilities is not a prudent course of action.

Frankly, the Trump administration should be lambasting companies like NIPSCO for continuing to pursue their voluntary decarbonization pledges when electricity bills are rising, and demand is soaring due to data centers. A few mean tweets might go a long way toward helping utility executives and their Wall Street investors understand they can no longer Green Plate the grid at the expense of everyday Americans.

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NERC’s 2019 Long-Term Reliability Assessment. Can you believe they didn’t even have the map of doom back then? Also, only Texas was thought to have insufficient power then. Simpler times.

A Method to estimate the economy-wide consequences of widespread, long duration electric power interruptions. We’re looking into how the national labs model the cost of blackouts based in duration, customer class, and how widespread the outages are.

Our goal is to raise our visibility by reaching the top 10 in our category, and because the leaderboard is mostly driven by revenue, moving to paid is pretty much the only way to move up.

For the time being, most of our articles will still be free. However, some, probably the extra juicy ones, will live behind a paywall for an undetermined amount of time. We’re still figuring things out on our end.

Thanks for being a loyal subscriber.

Disappearing Wind and Solar Cost Texans $766 Million Extra in 17 Hours

Everything’s bigger in Texas, including the power price spikes.

In the wake of Winter Storm Fern, the U.S. Department of Energy correctly noted that it was America’s thermal fleet that carried the day, as coal, natural gas, nuclear, and oil for our friends in New England provided 86 percent of the power generated during the peak of the storm, while wind and solar generated just 8 percent and 2 percent, respectively.

This is despite the fact that U.S. Energy Information Administration (EIA) data show wind and solar constituted roughly 23 of the total installed capacity on the grid in January, meaning they punched below their weight when the grid was stressed.

With egg on their faces, the American Clean Power Association (APCA), the top lobbying arm of the wind and solar industry, hastily started up the spin machine for damage control. As a result, it issued this website claiming that wind and solar saved consumers more than $2 billion during the winter weather event, including $200 million in savings in the Electric Reliability Council of Texas (ERCOT) Region

However, ACPA doesn’t disclose how it calculated those figures, and it didn’t respond to our emails requesting more information, so we did a little analysis of our own. We found that it is exceedingly unlikely that wind and solar saved Texas any money.

In fact, our analysis found that wind and solar disappeared just when they were needed most, costing Texans an additional $766 million in wholesale power costs in just 17 hours.

To understand why, it helps to know some background.

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ERCOT’s Generation Mix

For many years, ERCOT has become increasingly dependent weather-dependent resources, particularly wind energy, for meeting peak demand.

As we have noted on several occasions, ERCOT hasn’t added any net thermal capacity since 2013, and the amount of thermal generation on the system has decreased since 2016 despite the fact that peak demand has grown by over 12,000 megawatts (MW), or by over 17 percent in the last ten years.

According to EIA Form 860M data, ERCOT had 171,542 MW of total installed capacity on its system as of December 2025, with 87,430 MW of thermal capacity and 83,542 MW of wind, solar, and battery storage, as shown in the graph below.

On paper, this should have been more than enough capacity to weather Winter Storm Fern without a massive spike in prices, and for some of the time it didn’t. However, around 5 pm on January 25th, ERCOT experienced a substantial drop in wind and solar generation. At 10 pm, the thermal fleet was delivering a maximum output of 66,087 MW of power, while wind delivered 6,025 MW, solar delivered zero, and battery storage consumed 319 MW for charging, which led to tight system conditions.

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Wholesale Power Prices: Ready for Liftoff

These tight system conditions led to a massive spike in power prices in ERCOT.

Day-ahead and real-time wholesale price data from S&P Global data show prices spiked in concert with wind and solar’s disappearing act. For instance, notice in the graph below that while prices (dark green line for Day Ahead, green line for Real-Time) increased slightly with the rise in demand, they didn’t spike until electricity production from wind and solar both plummeted.

Day-ahead prices reached a high of $1,832 per MWh, and real-time prices reached $871 per MWh, resulting in massive power costs for Texas families and businesses.

ERCOT data indicate that approximately 62.5 percent of all MWhs purchased in January of 2026 were bought on the day-ahead market, and 37.25 percent on the real-time market. Using this split, we were able to create a blended hourly wholesale power cost for consumers and determine the additional costs to consumers compared to wholesale power costs before the variable energy sources pulled their vanishing act.

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The graph below shows the combined hourly wind and solar capacity factor and the settled energy cost in ERCOT during Winter Storm Fern. It also shows the additional power costs, shaded in light red, incurred as a result of the drop in wind and solar generation, relative to a $20 million-per-hour power baseline cost, shown by the red line. The total additional cost of the light red areas is $766 million over 17 hours.

Our analysis used $20 million as the baseline because it was the approximate cost of power at 4 pm on January 25th, the hour just before wind and solar output dropped during the high-demand period.

The Anatomy of a Price Spike: Why Did They Rise So High?

Ultimately, the price increase was the result of high demand and inadequate supply.

Data from GridStatus shows outages for thermal units, wind, and solar during Winter Storm Fern. Wind and solar had lower initial outages, but outages spiked on January 24th as the cold front moved in.

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In contrast, thermal facilities had relatively low outage rates, with availability ranging from 88 to 90 percent during the price spike event, which lasted from the evening of January 25th through the morning of January 26th, then falling to 87 percent on January 27th.

The outages reduced ERCOT’s reserve margin, which we define here as the amount of installed thermal capacity on the system, minus outages, plus intermittent generation, available to meet demand during any given hour during the storm. We defined the reserve margin this way because wind and solar can (and did) fail to show up due to a lack of wind or sunlight, even if they are not technically on outage.

The graph below shows the amount of thermal generation available to meet peak demand, the amount of power provided by wind, solar, and battery storage, and the hourly demand on ERCOT from January 23rd through the 27th.

The red line shows the reserve margin, which dips from over 100 percent on January 23rd, when demand was lower, and wind, solar, and storage were able to deliver more power to the grid, down to just 15 percent starting at 5 pm on January 25th.

Unsurprisingly, the falling reserve margin is highly correlated with rising electricity prices. In fact, in an energy-only market like ERCOT, where the grid operator does not make reliability payments to dispatchable generators to be available during periods of high stress, like winter storms, high prices are the primary mechanism for keeping reliable plants online, as they capture huge amounts of revenue during these “scarcity events.”

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Wind, solar, and storage advocates will no doubt argue that wind and solar decreased wholesale prices when they were available, but the question isn’t whether it is possible for these resources to reduce wholesale costs at times (they absolutely can).

The questions are is the grid is properly valuing reliable generators and becoming over reliant on weather based resources, and could Texas achieve greater price stability and reliability at a fraction of the cost by adding more natural gas instead of wind, solar, and battery storage.

The graph below shows the wholesale electricity price in ERCOT by available reserve margin. Based on the data from Winter Storm Fern, the wholesale power price skyrocketed when reserve margins dipped below approximately 26 percent.

For the statisticians in the audience, this model has an R² of 0.91, meaning about 91 percent of the variation in ERCOT wholesale prices in this dataset is explained by changes in available reserve margin.

Because the high prices can be explained largely by the scarcity of the system, the solution is to add more dispatchable capacity that can boost the reserve margin, rather than rely on generation resources that could fall off the grid at any moment. For the last 25 years, ERCOT has been doing the latter.

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We thought it would be fun to try and estimate what the hourly cost of power would be based on building 10,000 MW of new natural gas capacity in ERCOT, which would probably cost $25 billion at today’s prices, by matching the blended wholesale power prices at a given reserve margin percentage in the original dataset to the MWh costs after boosting the reserve margins with new natural gas capacity.

This analysis found that the new gas capacity could have saved Texas families and businesses $1.27 billion in power costs, as shown in the graph below by the difference between the dark green and light green shaded areas. If any of our readers have questions, comments, or scathing rebuttals of the methodology, we look forward to discussing them in the comments.

Why Has ERCOT Failed to Add New Thermal Plants?

While natural gas additions have mostly offset coal retirements, ERCOT hasn’t added any net dispatchable capacity since 2003. This is largely due to the energy-only market structure, which does not properly value the differences in reliability between generators like gas and coal plants and intermittent resources like wind and solar generators.

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Furthermore, Texas does not require utilities to keep enough backup capacity online to make sure there are always enough reliable power plants available to meet electricity demand when the wind isn't blowing or the sun isn't shining. In fact, the market structure in Texas specifically incentivizes reliable generators to exit the market.

As we wrote in November of 2023:

This isn’t a bug of the ERCOT market; it is a feature. In a 2018 article in PVMagazine detailing a report by the WindSolar Alliance of Texas, the article author bragged about the parasitic effect [wind and solar] electricity generators have on the revenues of more reliable power plants:

This is just the beginning. Texas continues to add more wind every year, and ERCOT has estimated that the state could put online 13 GW of solar by 2030. This will ultimately mean more hours where coal and gas plants are not operating, and more retirements of conventional generation. [emphasis added]

In the case of ERCOT, the parasitic impact of wind, solar, and now battery storage has not led to retirements, but it has dissuaded new thermal generators from entering the market at a time when power demand is soaring due to population growth, industrial growth, and data centers.

[emphasis added]

Something’s gotta give.

Conclusion

The American Clean Power Association is full of hot air.

Rather than saving Texans $200 million during Winter Storm Fern, these energy sources skipped town when the chips were down, increasing wholesale power prices by $766 million compared to prices that occurred prior to their exit from the scene.

In contrast, if ERCOT had an additional 10,000 MW of gas on its system, Texans could have saved $1.27 billion in avoided scarcity prices.

Better luck next time, ACPA.

Have you ever wondered how not to do a grid reliability study? Well, dear reader, today is your lucky day!

In early February, the Union of Concerned Scientists (UCS) released a study titled New England’s Offshore Wind Solution, that claims “wind energy off the New England coast can powerfully reinforce the reliability of the region’s electric grid, particularly during winter when the system is most vulnerable to energy shortages.”

Specifically, UCS notes:

A Union of Concerned Scientists analysis of winter 2024–2025 wind speed data shows that the energy delivered by just two offshore wind projects, totaling 1,500 megawatts (MW) of capacity, would have lowered the risk of power outages, based on a key reliability metric, by 55 percent over the course of the season [emphasis added]. A larger fleet of 3,500 MW would have reduced the risk of outages by 75 percent. In either case, the scale of energy delivered by an offshore wind fleet would have increased the total winter energy supply from local renewable resources above the energy supply from imported liquefied natural gas.

These are bold claims about offshore wind bolstering grid reliability, especially because they rely on a single metric—energy generation— that doesn’t even account for offshore wind’s (in)ability to meet peak power demand using hourly load profiles.

This is exactly how not to do a grid reliability study!

A closer look at the UCS study reveals serious methodological shortcomings. In the end, UCS makes assertions about improving grid reliability with intermittent resources on the New England grid without addressing the intermittency of those resources themselves.

Despite these flaws, which are glaringly obvious to anyone with a working knowledge of the power sector, media outlets reported on the study largely without scrutiny. One in particular—E&E News by Politico—took a shortened and paraphrased version of what Isaac said via email and placed it in the final two paragraphs of its article. Unfortunately, this is just one example of why so many remain misinformed about intermittent energy resources.

This is where the EBB community comes in, including you. Please like and restack this piece so we can make sure UCS feels as humiliated as possible educate as many people as possible!

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The Metric UCS Relies On for Its Claims

When the UCS study says that offshore wind reduces the risk of power outages for ISO-NE “based on a key reliability metric,” the metric it uses is known as the daily energy demand.

Daily energy demand is a metric tracked by ISO-NE. It helps mitigate the risk of winter energy shortfalls when fuel supplies are constrained due to limited natural gas pipeline capacity. Specifically, ISO-NE produces 21-Day Energy Assessments to quantify this risk, describing their purpose as follows:

The purpose of this sophisticated assessment is to identify potential energy shortfalls while there is time to prevent them or lessen their impact. With up to three weeks’ notice, the report gives resource owners time to evaluate the status of their fuel supplies and to arrange for replenishment, as needed, or to reschedule maintenance in order to maximize availability.

Within these reports, ISO-NE highlights the peak forecasted daily energy demand on a scale from Lower Risk to Higher Risk.

Green represents low risk of energy shortfalls, yellow is elevated risk, orange is higher risk, and red is the highest risk.

This is the metric UCS relies on to claim that offshore wind “can powerfully reinforce the reliability of the region’s electric grid.” Ironically, UCS’s own analysis undermines this conclusion by indirectly revealing how unreliable intermittent generators actually are.

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The UCS’s Own Study Refutes Its Main Takeaway

The UCS analysis examines a cold-weather period on the ISO-NE grid from December 1, 2024, through February 28, 2025. During this period, daily energy demand exceeded the elevated-risk threshold of 350,000 megawatt-hours (MWh) on 53 of the 90 days (59 percent). On four of those days, demand exceeded 400,000 MWh—levels ISO-NE classifies as higher risk for energy shortfalls.

As UCS explains, this high daily energy demand “increased the region’s risk of an energy shortfall, a condition that can lead to a blackout.”

UCS’s central claim is that if ISO-NE had 1,500 MW of offshore wind, the added energy would have reduced net daily demand below 350,000 MWh on 29 of the 53 high-risk days—a 55 percent reduction. With 3,500 MW of offshore wind, UCS claims a 75 percent reduction.

UCS presents this data in the chart below, showing actual ISO-NE demand (black line), net demand after including 1,500 MW of offshore wind (blue line), and net demand after including 3,500 MW of offshore wind (purple line).

But a closer look tells a different story.

Figure 1 in the study (shown above) indicates that offshore wind would not have generated very much energy during the peak periods observed around December 22 and from January 19-26th. This data indicates that offshore wind generation dies down when it is needed most, during peak demand periods.

With 1,500 MW of offshore wind, the highest-risk days—those exceeding 400,000 MWh—remain firmly in higher-risk territory. And even 3,500 MW of offshore wind does almost nothing to reduce demand on the most extreme days; all four remain near the 400,000 MWh threshold.

This exposes the central flaw in UCS’s conclusion: the intermittency of offshore wind—entirely ignored by the study—still leaves ISO-NE vulnerable to blackouts on the days that matter most, even using UCS’s own chosen metric.

UCS applies no weighting to the highest-risk days and, as a result, incorrectly claims that offshore wind reduces blackout risk by 55–75 percent. That is not a fair assessment of offshore wind’s contribution to grid reliability.

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Worse still, the analysis relies entirely on daily averages. When hourly load shapes and generation profiles are examined, offshore wind performs even more poorly.

How to Actually Do A Grid Reliability Report

Daily energy demand is only an energy metric—it says nothing about reliable capacity. On its own, it is insufficient to support the claims UCS makes about offshore wind improving grid reliability.

A proper grid reliability study evaluates whether the system can meet peak demand. That is precisely where UCS’s conclusions fall apart, because peak-demand analysis exposes the intermittency of offshore wind and the risk of relying too heavily on weather-dependent resources—conditions that directly lead to blackouts.

By sidestepping this reality, the UCS report misleads readers about the reliability value of offshore wind, particularly in light of its concluding statement:

With continued support from New England leaders, the development of an offshore wind fleet promises to bring these reliability and affordability benefits home to consumers in the coming years.

Setting aside the “affordability” claim for now, we wanted to briefly mention that it relies on wholesale power prices while ignoring the fact that costs for offshore wind are borne by ratepayers through long-term power purchase agreements (PPAs), and that even downward pressure on wholesale prices would not prevent higher retail electricity rates.

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A meaningful reliability analysis would have focused on offshore wind’s ability to contribute during peak hours.

Our ISO-NE Report, For Example

In our ISO-NE report, we modeled the resource mix required to meet New England’s decarbonization mandates, with a focus on both cost and reliability.

Using hourly load shapes and historical weather years, our analysis shows just how little offshore wind and other intermittent resources contribute to reliability.

We first evaluated the 2024 ISO-NE Economic Planning for the Clean Energy Transition (EPCET) resource mix, which included more than 97 GW of new renewable capacity: 34,400 MW of offshore wind, 27,500 MW of solar, 7,500 MW of onshore wind, and 27,600 MW of battery storage.

Even with this massive buildout, the system failed to meet ISO-NE’s projected 2050 demand growth. Stress-testing the system with 2023 historical weather data revealed an 18-hour blackout in December caused by a prolonged wind drought.

As you can see, wind and solar resource output were minimal, imports were maxed out, and battery storage was fully depleted. A blackout of this magnitude in the middle of winter would be devastating for the region.

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After finding the EPCET resource mix inadequate, we modeled a system that could ensure reliability using the same 2023 data. That system required 66,000 MW of offshore wind, 68,300 MW of solar, 19,100 MW of onshore wind, and 42,900 MW of battery storage—more than double the total capacity in the EPCET study.

This modeled resource mix also included roughly 20,500 MW of natural gas capacity, 3,350 MW of nuclear, and 3,780 MW of hydro and pumped storage.

While this was sufficient to fill the reliability gaps for the 2023 historical test year, it wasn’t for other test years.

With nearly 19 times the offshore wind capacity UCS claims would reduce outage risk by 75 percent, ISO-NE would still experience blackouts during extended wind droughts. One example shows a six-hour capacity shortfall in December when tested against 2019 weather data.

Keep in mind that the data used for demand, generation, and weather inputs in our analysis were provided by ISO-NE.

This is what a real grid reliability study looks like—and the conclusion is unavoidable: offshore wind contributes very little to reliability, and more reliable and affordable solutions exist that can reduce the risk of blackouts on the ISO-NE grid.

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Conclusion and the Real Solution to New England’s Risk of Blackouts

ISO-NE focuses on daily energy demand for a simple reason: New England is dangerously reliant on just-in-time natural gas deliveries that compete with home heating and are constrained by insufficient pipeline capacity.

This is an issue has been sounding the alarm on for years.

The solution is not to overbuild the grid with intermittent resources like offshore wind, which are also energy-limited on days the wind doesn’t blow and the sun doesn’t shine. The solution is to build larger oil tanks, expand pipeline capacity, and invest in reliable, dispatchable resources with on-site fuel storage.

At least with thermal, fuel-based resources, constraints can be addressed by storing more fuel or building more pipeline capacity. With weather-dependent resources, the only option is massive overbuilding the grid to accommodate the issue of intermittency—and even that may not be enough.

Unfortunately for New England consumers, current decarbonization policies prevent these common-sense solutions from being implemented.

Despite the mounting evidence of reliability concerns when over-reliant on weather-based resources, reports like the UCS study—and the uncritical coverage they receive—continue to misinform the public about the real drivers of grid reliability.

Affordability has been the soup de jour of our national electricity discourse for the last several months, as power prices continue their relentless six-year climb upwards and liberal politicians seek to seize the growing discontent over ballooning bills to boost their electoral fortunes in the 2026 midterms.

Against this backdrop, Environmental Protection Agency (EPA) Administrator Lee Zeldin announced last week that the agency has ended the Endangerment Finding, the legal foundation for most federal climate regulations, for greenhouse gas emissions from mobile sources, hailing it as the single largest deregulatory action in U.S. history.

While last week’s rulemaking applies only to cars, trucks, and other mobile sources of greenhouse gas emissions, it is widely believed that these rules telegraph future rulemakings that will rescind the Endangerment Finding for stationary sources. Chief among these stationary sources are the nation’s coal and natural-gas-fired power plants.

Rather than rehash the mechanics of the repeal, speculate about potential court challenges, or discuss the policy implications moving forward, we wanted to meander down memory lane to demonstrate the impact of the Endangerment Finding and the subsequent regulations promulgated from it on electricity prices today.

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The Endangerment Finding Increased Electricity Prices

Needless to say, not everyone was pleased with the Endangerment Finding’s extinction. Former President Barack Obama took to Twitter to admonish the current administration over its actions, claiming that the nation would be less safe, less healthy, and less able to fight climate change without it.

Notably absent from this list is any mention of the impact of the Endangerment Finding—and its subsequent role as the basis of his Clean Power Plan— on electricity prices. The omission is astute, indicating that the former President is savvy enough to understand that his policies were designed to cause pain at the plug. Rising prices were a feature, not a bug.

For example, in 2008, Obama candidly admitted that his desired cap-and-trade system for greenhouse gases would cause electricity prices to “necessarily skyrocket.” He also noted:

“Because I’m capping greenhouse gases, coal power plants, natural gas [power plants], whatever the industry was, they would have to retrofit their operations, and that will cost money; they will pass that money on to consumers.”

Despite the House of Representatives passing Waxman-Markey, a Cap-and-Trade bill, and the Democrats briefly holding a 60-seat, filibuster-proof majority in the Senate in 2009, a Cap-and-Trade bill was never brought to the Senate floor, killing what was to be the basis of Obama’s climate agenda.

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Skinning the Cat

Having been rebuffed in his efforts to effectively enact a carbon tax, Obama was undeterred, stating, “Cap-and-Trade was just one way of skinning the cat; it was not the only way, it was a means, not an end, and I’m going to be looking for other means to address this problem.”

The result was a novel reinterpretation of the Clean Air Act under Sections 111(b) and 111(d) that the administration argued allowed it to regulate greenhouse gas emissions from new and existing power plants under the New Source Performance Standards (NSPS) and the Clean Power Plan (CPP), respectively.

The most consequential outcome from the NSPS was the emissions standards established for new coal-fired power plants in 2015. The emissions limit was set so low that anyone seeking to build a new coal plant would be required to install unproven carbon capture and sequestration (CCS) technology. As a result, there has not been a new coal plant built in the United States since the 932-megawatt (MW) Sandy Creek Station came online in 2013.

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With new coal plants effectively outlawed, the Obama administration turned its attention to the existing fleet, issuing the Clean Power Plan to limit carbon dioxide emissions from the power sector by establishing greenhouse gas emissions limits for each state.

State-based emissions reduction mandates were to act as a stick looming over the heads of utility resource planners and utility commissioners, “encouraging” them to retire their coal plants, rather than spend millions of dollars retrofitting them to comply with other increasingly onerous standards for coal plants, including the Mercury and Air Toxics Standards (MATS), Coal Combustion and Residuals (CCR), Effluent Limitations Guidelines (ELG), and Cross State Air Pollution Rules (CSAPR).

Fortunately for the entire industry, the U.S. Supreme Court granted an emergency stay of the final Clean Power Plan rules after states and industry challengers argued EPA had exceeded its authority and that compliance would cause irreparable harm. Later, the first Trump administration repealed and replaced the rule with the Affordable Clean Energy Rule.

Despite the death of the Clean Power Plan, the regulation’s promulgation has had a profound influence on the electricity sector for the last 10 years.

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The Chilling Effect

Climate advocates and wind and solar proponents like to have it both ways with respect to the long-term legacy of the Clean Power Plan.

On the one hand, they like to claim that the regulations played no role in influencing utility decisions to retire coal plants prematurely (and replace them with wind, solar, battery storage, of course) because they were stayed by the Supreme Court and rescinded by the first Trump administration. They argue that reductions in natural gas, wind, and solar prices did the heavy lifting of killing coal plants, and the EPA’s role was illusory.

On the other hand, they want to take credit for the fact that their reinterpretation of the Clean Air Act and issuance of the Clean Power Plan established the expectation that future regulations and policies would require utilities to reduce their greenhouse gas emissions, which contributed to companies including carbon costs or anticipated regulations in their Integrated Resource Plans (IRPs) and issuing voluntary pledges to achieve Net Zero emissions.

The latter was the perspective given by Jody Freeman on Heatmap’s Shift Key podcast. Freeman is the Archibald Cox Professor of Law at Harvard Law School and the Director of the Energy and Environmental Law Program. She was also the Counselor for Energy and Climate Change in the Obama White House from 2009 to 2010, and was the architect of President Barack Obama’s agreement with the U.S. Auto industry to double fuel economy standards and to regulate greenhouse gases under the Clean Air Act.

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On the show, Freeman argues that the Obama administration’s interpretation of the Clean Air Act was instrumental in implementing climate policy via regulations:

But the point of all this is to say you can make an argument. Well, look, this act hasn’t panned out. Right. We never got these power plant standards anyway. I would just disagree with this.

…Even the so-called failed Clean Power plan, that process helped to spur a decarbonization conversation among utilities and in the states that helped them plan for the future, and was really consistent with the market going in the direction of cheaper renewable energy, solar, wind, et cetera. So I still think the process around the clean power plan was really productive and helpful.

Freeman is correct. The Clean Power Plan, underpinned by the Endangerment Finding, was an effective lever because it introduced climate risk to the utility planning process. The utility industry operates on decade-long planning cycles, which means the introduction of this climate uncertainty introduced 11 years ago is still impacting power prices today.

Some states have adopted carbon taxes or regional cap-and-trade programs to reduce emissions and thus exposure to the risk that climate policy could leave coal and gas plants as stranded assets, while other states, like Minnesota and Colorado, adopted state-specific Social Cost of Carbon (SCC) metrics for resource planning.

In many other states, even those that are traditionally “redder,” like Louisiana or Arizona, utility companies like Entergy and Arizona Public Service incorporated a cost of carbon dioxide emissions in at least some of their planning scenarios, stacking the deck in favor of wind, solar, and natural gas buildouts.

On top of that, virtually every Investor-Owned Utility adopted self-imposed Net Zero goals to enrich shareholders reduce emissions.

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The Obama Influence, Today: Unnecessarily Skyrocketed

The Endangerment Finding was the first step in a regulatory road that has ultimately led to a widening chasm between climate-centric states, which vote overwhelmingly for Democrats, and cost-centric states, which predominantly vote for Republicans.

As a rule, the states that have been the most aggressive in enacting climate policies—like carbon pricing, wind and solar mandates, and rejecting pipelines—have the highest electricity costs, which we were able to demonstrate in our map from the Blue States, High Rates report, which Always On Energy Research partnered on with the Institute for Energy Research.

In fact, it is often easier to explain why some Blue states are the exceptions to the rule, with electricity rates below the national average, than it is to argue that Blue-state policies don’t drive up prices.

Some states, like Washington and Oregon, have costs below the national average despite their best efforts to change that, thanks to bountiful hydroelectric power that reflects the “greenness” of the original New Deal.

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New Mexico’s electricity costs are low thanks to the oil and gas industry, which delivered the nation's lowest delivered-cost of natural gas in 2024 ($0.99 per million British thermal units). In addition, a surge in load growth to power the oil and gas industry has more than doubled the industrial electricity consumption in the state since 2008, spreading fixed capital costs over more MWhs, thus reducing rates.

Minnesota and Colorado are currently below the national average, as well, but that is largely because they started far below it. Their cost advantage has eroded dramatically after enacting wind and solar mandates in 2007.

The growing rift in state energy policies is causing a predictable dynamic where the delta in costs between red states and blue states is widening over time.

made the chart below, which shows the increase in residential electricity rates for Blue states, Purple States, and Red states from January 2019 through November 2025. Blue state price increases are nearly twice the Red state average during this time.

Conclusion

Obama’s legacy is one of electricity prices “necessarily skyrocketing” for those states that have most aggressively followed his example and have sought to reduce their carbon footprint.

The end of the Endangerment Finding, should it hold up in court, will only accelerate the divergence in policies and prices between the Blue states and Red states. In this scenario, the threat of federal greenhouse gas regulations will be greatly diminished, and it should hold far less sway over decisions to retire coal plants or build wind and solar facilities to hedge against the risk of future climate policies.

In other words, if you like your power plant, you’ll be able to keep it.

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Give us a like and share this piece, or your power bill will necessarily skyrocket

Cost Allocation Is Destiny: Why Digital Infrastructure Economics Now Runs Through the Rate Case by

Solar and wind aren’t real power sources, they’re intermittent fuel-savers by

The Water Vapor Problem by

Most public discussions about solar focus on energy production, but power systems are built around reliability during peak demand. Once you look at the grid through the lens of accredited capacity—that is, capacity that can be relied upon during peak demand—instead of annual energy, the land requirements for different technologies look radically different.

This is the energy vs. capacity distinction that most solar land-use debates miss.

Last September, we were retained by Cerro Gordo County, Iowa, to provide expert witness testimony on a proposed 500-megawatt (MW) solar facility, the River City Energy Project. If you are interested in retaining us for a utility proceeding, please reach out to us by clicking here.

As part of the proceedings in the Generating Certificate Utility (GCU) docket GCU-2025-0004, we were responsible for evaluating the land-use and economic impacts of solar in Cerro Gordo County and how it would compare to a new combined-cycle (CC) natural gas (CC) facility.

For today’s analysis, we’ll focus on the land-use impacts of solar; they are worse than you think.

Long story short, matching the accredited capacity of one natural gas plant sitting on 58 acres of land with solar in 2030 would require over 105,792 acres of solar panels, roughly 29% of the total land area of Cerro Gordo County.

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The River City Energy Project

The River City Energy Project is a 500 megawatt (MW) solar farm proposed by Ranger Power in Cerro Gordo County, Iowa. If approved, the total project site would be 2,894 acres, most of it on farmland, equating to an average of 5.8 acres per MW of installed capacity.

In contrast, the Emery Generating Station, a nearby CC natural gas plant also located in Cerro Gordo County, has a total rated capacity of 602.8 MW and sits on a total of around 58 acres. Including the power plant and the parking lot, land use for this CC plant equates to 0.096 acres per MW of installed capacity.

This means the proposed Ranger Power solar facility would require 60 times more land per MW than a CC natural gas plant of equal size.

The disparities in land use become more evident when the reliability and resource adequacy attributes of each resource are considered.

Today’s Key Word is Capacity Value. Do You Have Any?

In testimony in favor of the proposed solar project, River City Witness Waylon Brown stated the Ranger Power project is expected to garner a “about 50 percent capacity credit in spring, summer, and fall,” from the Midcontinent Independent System Operator (“MISO”).

However, Mr. Brown’s stated values are not at all reflective of the projected capacity values that will be attributed to wind and solar in the coming years because MISO is revising its capacity accreditation methods to better reflect the reliability contributions of all resources on its system during periods where the system is most likely to experience loss of load hours.

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The shift away from Effective Load Carrying Capacity (“ELCC”) to Direct Loss of Load (“DLOL”) accreditation will have important implications for the reliability metrics assessed for each resource class.

Table 1 shows the indicative seasonal capacity accreditations that solar facilities would receive in the 2025-2026 planning year using DLOL, and the DLOL assumptions used in 2030, 2033, and 2043 in the MISO 2024 Regional Resource Assessment and Technical Appendix.

MISO documents also show the projected capacity accreditations of combined cycle natural gas facilities using DLOL during the same period. Annual average capacity accreditations are expected to be 86% in the 2025-2026 Planning Year, 82% in 2030, 81% in 2033, and 81% in 2043 (See Table 2).

Comparing the proposed Ranger Power project with a new 500 MW combined cycle natural gas facility yields substantial differences in the accredited capacity awarded to each 500 MW facility. Figure 2 adjusts the total installed capacity of each resource by its annual average capacity value to determine the annual average accredited capacity each project would provide to the MISO system.

By dividing the total acreage of the proposed Ranger Power project and a new natural gas plant by its accredited capacity from Figure 2, we can determine the number of acres needed to provide one MW of firm accredited capacity to the MISO system in each Planning Year, shown in Table 3.

The low capacity value attributed to solar using the DLOL metric would necessitate 19.29 acres of solar panels for one MW of accredited capacity in the 2025-2026 planning year, compared to 0.14 acres for a combined cycle natural gas plant. In 2030 and 2033, it would require 257.24 acres of solar panels for one MW of accredited capacity, growing to 578.80 acres in 2043.

In comparison, natural gas would require 0.14 acres, 0.14, and 0.14 acres in 2030, 2033, and 2043, respectively.

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In the interest of maximizing the efficiency of land used for electricity generation, it is illustrative to compare the acreage needed to provide the same capacity value of the proposed Ranger Power facility and a new natural gas plant.

Figure 2 above shows the accredited capacity a new gas plant could expect to receive under the DLOL accreditation metric. Table 4 below displays the number of solar acres needed to match the capacity value of the hypothetical combined cycle natural gas plant in each illustrative planning year and compares this total to the land area of Cerro Gordo County.

Matching the accredited capacity of one natural gas plant with solar in 2030 would require over 105,792 acres of solar panels, roughly 29% of the total land area of Cerro Gordo County.

Now, Let’s Do All of Iowa

According to MISO’s Planning Resource Auction results for the 2025/26 Planning Year, Load Zone 3 covers basically Iowa, slivers of Southern Minnesota, and a tiny part of Northern Illinois.

According to the MISO documents, this region has a peak summer planning reserve margin requirement of 11,116 MW.

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If we were to meet this with natural gas, it would require 1,296 acres of land, which is 0.0036 percent of all the land in Iowa. In contrast, meeting this capacity obligation with solar would require 2.86 million acres, or roughly 8 percent of the state’s total landmass.

For the math majors at home, this means it would take 2,207 times more land to meet Iowa’s capacity needs with solar than with natural gas. Just for fun, let’s look at how this looks in a bar chart.

The most obvious retort to the information in this graph is “no one is going to depend on solar to provide all of the capacity needed to meet your peak demand and reserve margin.”

However, as we saw in Witness Brown’s testimony, solar advocates have been crowing about the capacity value of the resources without acknowledging that it is about to drive over a cliff under DLOL, rendering it essentially useless as a capacity resource.

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Conclusion

These land use implications are not unique to Iowa, they are a structural feature of how modern power systems are planned. Resources that produce lots of energy but little firm capacity can look efficient on a megawatt-hour basis while requiring enormous physical scale to meet reliability requirements.

Solar can provide energy to the power system, but it is becoming increasingly clear that its value as a capacity resource is diminishing quickly. This has obvious implications for reliability, but it will also impact utility planning and land use issues that are playing out at utility commissions across the country.

Fear not, your tireless Energy Bad Boys will continue applying this same capacity-based framework to other states and technologies in upcoming analyses. All we ask in return is for you to share, subscribe, and give us all of your money.

High electricity rates a regional, not national, trend – study S&P Global

“A widely reported increase in average retail rates in the US has been interpreted as indicative of a broader, national trend. This is not the case,” Charles River Associates, or CRA, said in the report.

“Rather, in a few states and regions, rates have increased rapidly, putting upward pressure on the national average. Retail electric rates have generally been stable in other regions,” the firm said.

NY Democrats propose data center development moratorium S&P Global

Is New York even serious anymore?

States step up efforts to permit renewables ahead of US tax credit deadline S&P Global

Blue states rush to help themselves to your tax dollars

"Oregon's executive and legislative actions follow moves in Colorado, California, New York, New Jersey and Maine" to speed up the construction of wind and solar projects to qualify for federal subsidies.

Last Friday, the North American Electric Reliability Corporation (NERC) released its 2026 Long-Term Reliability Assessment (LTRA).

The map below says it all.

Nearly half of the American population will be at a high risk of rolling blackouts in the near future due to rising electricity demand, the announced retirement of reliable coal plants, and a continuing shift toward the unreliable wind, solar, and battery storage systems that failed to deliver during Winter Storm Fern.

The LTRA’s Executive Summary minces no words:

The overall resource adequacy outlook for the North American BPS is worsening: In the 2025 LTRA, NERC finds that 13 of 23 assessment areas face resource adequacy challenges over the next 10 years. Projections for resource and transmission growth lag what is needed to support new data centers and other large loads that drive escalating demand forecasts. Most new resources in development to come on-line in the next five years consist of battery storage and solar photovoltaic (PV), which are inverter-based and weather-dependent resources that increase the complexity of planning and operating a reliable grid. Meanwhile, more fossil-fired generator retirements loom in the next five years, reducing the amount of generation that has fuel on site and impacting the system’s ability to respond to spikes in demand. The continuing shift in the resource mix toward weather-dependent resources and less fuel diversity increases risks of supply shortfalls during winter months [emphasis added].

To ensure there are sufficient resources for supplying electricity in the future and to reliably meet the growing electricity needs for North Americans, industry, regulators, and policymakers need to be vigilant for shifting projections, keep plans for deactivating existing generators flexible, expedite system development, and perform robust adequacy assessments of future scenarios [emphasis added].

As a result, many regions of the country face an elevated risk of blackouts in 2026 and 2026, and a high risk from 2028-20230. The table below shows each region and its risk level by year, as well as a summary of the factors driving those risks.

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In a nutshell, high-risk areas are seeing rapid demand growth, coal retirements, and insufficient replacement capacity consisting largely of wind, solar, and storage, which do not offer the same reliability benefits as thermal resources.

Here are some interesting insights from the LTRA report.

In Demand Data Centers

According to the LTRA, data centers and other demand drivers will increase the peak electricity demand on the power grid by 224 gigawatts (GW), or 29 percent, in the summer and 245 GW, or 35 percent, in the winter over the next decade.

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The LTRA included a fascinating map that identified the drivers of load growth across regions of the United States. You’ll notice that data centers are major factors in nearly every region of America except California, New York, New England, SERC East, SERC West, and SERC FP (Florida).

In the Northeast, vehicle electrification and heat pumps are assumed to drive load growth, but we are deeply skeptical that this projected demand for power will materialize. High energy bills are already undermining public support for measures like Mass Saves, which charges natural gas customers an additional fee to subsidize heat pumps, and electric vehicle sales have plummeted in the wake of the expiration of federal subsidies. Not to mention, similar to data centers, it remains to be seen whether these regions will even be able to take on the increased demand stemming from electrification efforts.

Regardless of whether heat pump and EV demand increases are oversold, demographic changes, rising industrial demand, and data centers present a massive challenge to grid reliability in the 10-year period examined by NERC.

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Delaying Retirement

Meeting the projected demand growth in the years to come would be exceedingly difficult under any circumstances. However, it will be infinitely harder if we continue to prematurely retire existing reliable power plants, like the coal plants that increased their output by 31 percent during Winter Storm Fern compared to the previous week to keep the lights on.

According to the report, as much as 105 GW of fossil and nuclear capacity could go offline by 2035. The Midcontinent Independent System Operator (MISO), unfortunately, continues to lead the pack in projected retiring capacity at roughly 35 GW, shown in the bottom figure—all of it labeled as “confirmed” retirements.

With this in mind, it’s no wonder that MISO is projected to have the lowest reserve margin among the summer-peaking systems of just 4.3 percent by 2030, and that it shows a 7 GW shortfall of capacity by the winter of 2028.

If the first rule of holes is to stop digging, the first rule of electric grid reliability is to stop shutting down reliable power plants, including those powered by coal.

NERC urges state policymakers and utilities to “keep plans for deactivating existing generators flexible,” a polite way of asking them to stop making it harder to keep the lights on. This is something we have been advocating for years, and it is good to see NERC is inching its way toward screaming it from the rooftops.

NERC went on to highlight how some backtracking on plant retirements has already taken place, and that it is due to the reliability risks posed by shutting them down.

Projected retirements overall, both confirmed and unconfirmed, have shrunk from the prior year’s LTRA as reliability needs have expanded with the continued growth in anticipated large-load interconnections. The initiation of market mechanisms like capacity accreditation has also more precisely highlighted the loss-of-load risks posed by a generation mix that has increasing amounts of variable resources. Growing demand and evolving planning methodologies have highlighted the potential need to keep resources, particularly non-variable resources, on-line longer than previously anticipated.

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Building Stuff That Doesn’t Work Will End Badly

Lastly, NERC warns that “The continuing shift in the resource mix toward weather-dependent resources [i.e., wind, solar, and battery storage] and less fuel diversity [as coal plants retire] increases risks of supply shortfalls during winter months.”

New battery and solar represent around 66 percent of the capacity additions of the Tier 1 and Tier 2 resources in the study period. Natural-gas-fired generator additions represent 15 percent of the projected capacity additions, followed by wind and hybrid at 8 percent each.

We can’t keep trying to replace dispatchable power with intermittent resources and expect to keep the lights on. Thankfully, the Trump administration has taken aggressive action to shore up grid reliability and keep costs as low as possible.

Much of the blackout projections for high-risk areas in the LTRA report, like the Midwest and Mid-Atlantic, are based on policy-driven coal generator retirements, as these reliable, affordable power plants were under attack from the Biden EPA, and many remain in jeopardy due to state climate mandates.

For example, in 2024, the Biden administration finalized EPA regulations on carbon dioxide emissions from power plants that would have effectively killed off the remaining coal plants and made it much more difficult to invest in the new natural gas facilities we desperately need. These regulations are now being rescinded, and as a result, utilities have no excuse to endanger the grid or worsen the affordability crisis already grabbing headlines by retiring their coal or natural gas facilities.

In states with carbon-free electricity mandates, such as Colorado, Michigan, and Washington, the Trump administration is issuing emergency orders to keep existing coal plants running. While these orders have been criticized by climate groups, keeping the plants online provided vital capacity during last week’s cold snap, when highly subsidized wind and solar facilities decided not to show up for work.

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Conclusion

If only tax dollars could make the wind blow or the sun shine.

Alas, last week’s wind and solar failure highlights the fact that America’s energy policy has had the exact wrong priorities for decades, dishing out lavish subsidies for unreliable wind and solar generators — a bipartisan problem — and shuttering reliable nuclear and coal-fired power plants.

The One Big Beautiful Bill Act has begun to correct for this malinvestment in the energy sector by accelerating the phaseout of wind and solar subsidies — although Congress should have ended them immediately — sending a signal to the power industry that its capital is better invested in the reliable, dispatchable resources needed to meet the rising demand laid out by NERC.

Fixing what ails the grid will require states and utilities to first do no harm by shutting down reliable power generators, but it will also require Congress to understand that you can’t fix a reliability crisis by subsidizing unreliable resources.

NERC’s analysis is a clear warning that dimwitted policy will leave us all in the dark. Hopefully, it’s not during another winter storm.

This piece is a modification of an article published this week in the National Review.

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AOER In the News: It’s been a big week for the Always On Energy Team in the media, so we’re going to do a little bragging instead of having a “what we’re reading” section this week.

• On Monday, was in Town Hall with an article on the North American Electric Reliability Corporation (NERC) Long Term Reliability Assessment (LTRA).

• On Wednesday, Isaac was quoted in E&E News, criticizing an offshore wind propaganda piece by the Union of Concerned Scientists.

• On Thursday, Mitch and Isaac were in the National Review, also on the LTRA.

• On Friday, Isaac and Jonathan Lesser talked electricity affordability in RealClearPolitics.

Winter Storm Fern rolled through the United States last weekend, leaving hundreds of thousands without power as ice and freezing rain brought down tree limbs and distribution lines in several parts of the country.

Unlike Winter Storm Uri and Winter Storm Elliot, there were no blackouts due to a lack of power generation. However, that does not mean there weren’t some close calls and some uncomfortable lessons learned from Fern in MISO, ISO-New England, ERCOT, and PJM.

1. MISO: The Closest Call

Things got a little dicey early on January 24th in the Midcontinent Independent System Operator (MISO) territory, as the Regional Transmission Organization (RTO) declared Energy Emergency Alert 2 (EEA2), the step immediately below firm load shedding (EEA3).

One reason for the EEA2 was likely that the wind decided not to show up for work during the storm, as wind speeds cratered due to the cold weather. The graph below shows the hourly capacity factors for the region’s wind fleet fell from over 60 percent before the storm to just 7 percent at midnight on the 24th, far below the winter capacity value of 29 percent given to the resource from MISO.

If wind had been operating at its capacity value, it would have provided 9,640 MW of power during the storm. Instead, it bottomed out at 2,390 MW.

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Of course, people like Jesse Jenkins took to Twitter to defend wind and solar during the storm, arguing that “different resources play different roles at different times” as an attempt to obfuscate the fact that his preferred resources were doing badly when it mattered most.

Richard Meyer of the American Gas Association had the perfect reply. If we build our energy systems to manage peak demands, then we would be foolish not to observe how each resource performs during those peaks.

2. DOE’s Section 202(C) Orders Look Pretty Smart

Given the wind’s disappearing act in MISO and the EEA2 declared, the Section 202(C) emergency orders issued by the U.S. Department of Energy (DOE) to keep three coal plants running in MISO look pretty smart.

These orders include the Campbell Plant in Michigan (1,420 MW), and the Schahfer (847 MW) and F.B. Culley (104 MW) plants in Indiana.

We don’t have real-time access to the generation of these facilities, but if they were operating at their full combined nameplate capacity of 2,371 MW, these three facilities alone would have generated only 19 MW less than the entire MISO wind fleet of 33,244 MW at 1 a.m. on January 24th.

Hopefully, we will get the actual generation data from DOE at a later date, but maintaining 2,371 MW of dispatchable capacity as an insurance policy looks like a solid call, given the fact that the wind went Missing In Action.

3. ISO-NE: A Tale of Oil and Water

ISO-New England’s experience of Winter Storm Fern can be summed up as a tale of oil and water.

As documented by , , and Ken Girardin, New England was burning oodles of oil during the cold snap, as natural gas prices surged and power plants competed with residential home-heating customers for methane molecules.

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The graph below shows that oil became the single largest supplier of power to the grid during much of the cold snap. Nuclear was steady, wind had its ups and downs, but solar completely disappeared after the 24th, peaking at a three percent capacity factor on the 25th and the 27th.

The other aspect of this story is water. Specifically, hydroelectric power that was supposed to be available to ISO-NE from Hydro-Québec via the brand-new 1,200 MW, New England Clean Energy Connect (NECEC) transmission line, which was celebrated by Massachusetts Governor Maura Healey when it was placed into service on January 16th.

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Fast forward about one week, and there wasn’t much to cheer about. According to S&P Global, electricity flows along the line were suspended on January 24th due to increased power demand in Québec. According to Hydro-Québec COO Serge Abergel:

"The polar vortex has brought extreme and sustained cold air across Québec since the weekend. The surge in demand for power in Québec caused us to suspend deliveries over the New England Clean Energy Connect from Saturday afternoon [Jan. 24] until 6 p.m. [Jan. 26] when they resumed gradually, with full contracted deliveries flowing at around 9 p.m. There were also partial deliveries between 1 p.m. and 3 p.m. on Sunday."

According to Dan Dolan, the President of the New England Power Generators Association, the structure of the PPAs allows Hydro-Québec to halt power deliveries:

“NECEC does not have a reliability-based capacity contract, and that means that New England must be prepared for the significant changes in flows during stressed conditions like this week,” Dolan said on Jan. 27. “NEPGA has long highlighted throughout the policy debate in the development and regulatory approval of the NECEC contract, and the region is now dealing with those consequences.”

In fact, during some portions of the storm, ISO-NE was exporting power back to Québec along the NECEC line, as Meredith pointed out in her article, Don’t Look North. Even the U.S. Energy Information Administration (EIA) got in on the dunk-fest, producing the chart below, which shows hourly electricity trade between ISO-NE and Canada during the storm.

We warned of this possibility in our 2024 report on New England’s decarbonize/electrocute everything policies:

A key component of the ISO-NE decarbonization strategy consists of importing electricity from New York and Canada during periods of high demand and low wind and solar output. Our analysis is conservative because it assumes all 6,675 MW of the existing and planned transmission projects to import electricity into New England are firm, meaning they can deliver their full rated capacity at any point when needed.

Canadian imports, meanwhile, could also be subject to interruption. Hydro Quebec (HQ) is the largest exporter into the ISO-NE region, sending significant amounts of power to the New England states in the summertime.82 This is possible because Quebec, with 71.4 percent of households using electric heating and heat pumps in 2021, is a winter peaking system, and ISO-NE is currently a summer peaking system.

In February of 2023, a cold snap enveloped Quebec, causing electricity demand to reach new all-time highs. During this period, HQ demand reached 42,472 MW, outstripping the installed capacity of 37,200 MW on the HQ system.84 As a result, HQ had no power to send to New England. In fact, it was importing power from neighboring regions, including New York, Ontario, and ISO-NE.

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4. PJM: Yawn

PJM also burned some oil to keep the lights on, but overall, things were pretty tame because demand only hit a little over 140,000 MW, well below the 147,200 MW the grid operator had originally predicted, which would have shattered the record set in January of 2025.

Reuters reported outages of 21,000 MW on the 26th, a far cry from the 57,000 MW that were unavailable during Winter Storm Elliot in 2022.

5. ERCOT: Higher Demand Could Have Been Nasty

ERCOT avoided another Winter Storm Uri, but it wasn’t all sunshine and rainbows for the wind, solar, and battery storage crowd in Texas.

did a very nice write-up on the situation in ERCOT in the wake of Fern, and we would be foolish to reinvent the wheel. Please subscribe to Kerry’s Substack, A Pragmatic Approach To Energy.

As temperatures fell, outages for wind and solar jumped, as you can see in the two graphs below from Kerry’s article.

Texas may have been saved by lower power demand. According to the EIA, overall demand in ERCOT peaked on January 26th at around 75,000 MW, approximately 10,000 MW below forecast.

Our friend Dr. , the policy director for Life: Powered, an initiative of the Texas Public Policy Foundation, recently published a timely report on the risk of outages in ERCOT due to winter storms.

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Bennett’s analysis modeled a 1-in-10-year storm and assumed peak system demand in the 85,000-90,000 MW range. The results indicate that Texas may not have been able to handle Winter Storm Fern if demand had been higher without a significant contribution from the state’s wind fleet.

Texas is lucky that it wasn’t a few degrees colder. During the system peak of 75,263 MW at 9 am on January 26th, the wind was producing just 6,957 MW, operating at just 16 percent of its potential output.

This is bad, but it gets worse when we consider that ERCOT’s Monthly Outlook for Resource Adequacy report for January 2026 assumed wind would operate at a 40 percent capacity factor during the hour with the highest reserve-shortage risk at (Hour Ending 8 am Central), producing 16,287 MW.

Texas has less gas, coal, and nuclear capacity than it did 10 years ago, while peak winter demand has grown by over 30 percent. In the 5 years since Winter Storm Uri, the ERCOT region has added 31 GW of solar, 9 GW of wind, and only 3 GW of gas. If this trend continues, Texas will soon be in the dark even in minor storms like Fern, much less a storm like Uri.

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Conclusion

Despite hitting much of the U.S., Winter Storm Fern didn’t bring on the high demand that previous winter storms brought. But this much is the same: the wind didn’t show in MISO, or in many other places.

In addition, DOE deserves its victory lap, ISO-New England is probably regretting spending $1.6 billion on a transmission line that sent them no power during periods of high demand, maybe PJM’s gas winterization projects in the wake of Elliot paid dividends, and Texas will probably continue whistling past the graveyard when it comes to making sure is has adequate firm capacity for the next winter storm.

Thank you for reading Energy Bad Boys!

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The 2026 Long-Term Reliability Assessment from the North American Electric Reliability Corporation. The map pretty much sums it up.

Massachusetts’ Terrible, Horrible, No Good, Very Bad Energy Weekend by

Data Centers Are Not the Villain by . “Data center demand is revealing, not causing, this problem.” What a great line.

This is our 100th post on the EBB Substack! Whether you’ve been around for all 100, or are relatively new, we just want to thank everyone for making EBB what it is. We hope to keep delivering great content for you all that can be used to advocate for rational energy policies around the country.

Now, into the actual piece.

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The Energy Affordability Bait and Switch

The energy world seems to got through phases of what it deems the “it” thing.

For a while, it was decarbonization. Then, after thermal plants started shuttering and blackouts became very real possibilities due to a lack of power supply, reliability became front and center. Last year, all of the talk was about the skyrocketing demand for power from data centers.

Currently, energy affordability is suddenly the New Kid In Town, now that prices have swung dramatically upward in the last few years in much of the country, but predominantly in blue states.

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Energy costs are increasingly becoming a larger percentage of American family incomes, and while political leaders across the spectrum have all seemingly taken up the cause of lowering costs, some may just be paying lip service to the new “it” thing.

Many blue states have been forced to pull the plug on some of their more expensive energy initiatives, such as in New York and California (as we noted in a recent post), yet Democrats still can’t seem to help themselves from pursuing outrageously expensive energy policies.

Like all new kids on the block, they may just be biding their time until the next one comes around—using “energy affordability” to pursue the same unaffordable policies.

Take the newly elected governors in Virginia and New Jersey, for example.

Virginia Rejoining RGGI

In her first address to the Virginia legislature, newly elected Virginia Governor, Democrat Abigail Spanberger, made quite the splash.

Not only did she recommit the state to building more wind, solar, and battery storage, which will raise costs and won’t be able to meet the state’s anticipated growth in demand, she also announced that Virginia will be rejoining the Regional Greenhouse Gas Initiative (RGGI) that former Republican Governor Glenn Youngkin pulled out of in 2024.

Governor Spanberger noted that her decision to rejoin was based on electricity costs, saying, “Withdrawing from RGGI did not lower energy costs. We have seen them rise.”

This actually isn’t entirely true. But before we get to that, what exactly is RGGI?

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What is RGGI?

RGGI is a cap-and trade program that places a cap on carbon emissions from power plants in participating states. It mandates carbon-emitting plants purchase allowances (equal to 1 short ton of CO2) from auctions, and they must hold enough allowances to cover their emissions for the compliance period.

There is only a certain number of allowances that decrease every year, meaning that reliable power plants like coal and natural gas will be forced to run less as time goes on, and may even be forced to shut down if the program makes them uncompetitive on the market.

The proceeds from the program are redirected back to the states and are taken straight out of the pockets of ratepayers in the states that participate.

André Béliveau, writing in RealClear Pennsylvania, describes the impact of RGGI as the following:

Cap-and-trade schemes are a tax on modern life. They punish consumers, encourage deindustrialization, and arbitrarily manipulate markets in ways that do more harm to our economic environment with no clear positive impacts on our natural environment.

How It Raises Energy Costs

As Béliveau notes, RGGI acts as a tax that families and businesses are forced to pay, and in Virginia, it previously showed up as a line item fee on bills.

From 2021-23, $830 million in RGGI-related expenses were passed directly to ratepayers in the state, artificially increasing energy costs for Virginia families and businesses.

What does the state spend the proceeds from RGGI on? Mostly to fund flood mitigation and energy efficiency programs.

For the most part, however, these initiatives won’t help offset the cost increases brought on by the RGGI carbon tax, especially when you factor in the fact that it produces an incentive to build less-reliable resources like wind and solar that increase total system costs.

As we will explain in a future post, not even energy efficiency can help save money on a green energy electric grid, as the majority of costs become fixed and must be recouped no matter how much electricity is used.

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Costs Dropped After Leaving RGGI

It may come to a surprise to Governor Spanberger, but overall electricity prices in Virginia slightly dropped the year after former Governor Youngkin pulled Virginia out of the program, from 10.68 cents per kilowatt-hour (kWh) to 10.62 cents/kWh, after a 17 percent jump in prices from 2021 to 2022.

The decrease in 2024 was led by the drop in commercial electricity prices, while residential and industrial rates both leveled off.

When looking at residential prices in Virginia during its participation in RGGI, Virginia families experienced the single largest year-to-year price increase in over two decades in 2022 of 11.5 percent, followed by another 6.9 percent increase in 2023. After Virginia left the program in 2024, residential electricity prices leveled off and increased by only 1 percent.

While many factors may have impacted both the jump in rates and the leveling off, adding a carbon tax to the bills of ratepayers certainly didn’t help—and the fact remains that overall prices in Virginia skyrocketed during participation in RGGI and fell after leaving RGGI.

This calls into question Spanberger’s entire reasoning for rejoining RGGI, which will once again put upward pressure on Virginia electricity prices and penalize reliable generators for carbon emissions at a time when the state needs all the power it can get. Dominion Energy, the state’s largest electric utility company, said as much in its most recent rate case.

After noting the recent trends in the PJM market, where retirements are outpacing additions and significant load growth is anticipated from data centers, Dominion stated:

Today, the Company needs as much generation capacity as it can get.

With RGGI, which essentially places limits on existing thermal generators, tapping into the state’s existing resources and building new, reliable generators will become much more difficult.

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New Jersey Commits to Solar and Storage

The newly elected New Jersey Governor, Democratic Mikie Sherrill, is another policymaker who seems to be promoting Affordability-in-Name-Only policies.

If her proposals are to be taken seriously, she wants to increase spending without paying for it.

On her first day in office, Governor Sherrill signed multiple executive orders—one of which was to freeze electricity rate increases and explore ways to decouple utility profits from capital spending, and another calling to build more solar and storage facilities.

While Governor Mikie Sherrill is issuing these orders in the name of “affordability,” she either fundamentally misunderstands why costs have become so expensive or is simply using the new “it” topic of energy affordability to push the same policies that have led to the reliability and affordability crises we now face.

Her executive orders show these misunderstandings clearly.

Myth #1: Growing Demand Is To Blame for Supply Issues

Governor Sherrill’s Executive Order No. 2 is riddled with claims that “demand is exceeding supply,” and that this is because PJM is experiencing significant load growth. New Jersey, the executive order notes, now anticipates load growth for the first time in two decades.

While this is true, this is only half of the story.

The other half is the loss of firm capacity in the state.

After peaking at 19,400 MW of capacity in 2014, New Jersey has retired over 3,700 MW of coal, natural gas, oil, and nuclear capacity, and has replaced it with just over 800 MW of mostly solar capacity.

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To say the least, 800 MW of solar capacity to replace 3,700 of reliable capacity is insufficient, and is a trend playing out on the entire PJM market. Today, New Jersey only has about 16,600 MW online, representing a net drop of 2,800 MW since 2014.

This is important to remember when blue-states, in particular, try to offload their reliability issues on the rise of data centers, which are relatively recent development in the energy world.

The reliability issues we face today are 10-20 years in the making, and if Governor Sherrill cared about affordability, she would recommit the state to reliable resources, cancel the state’s Renewable Portfolio Standard (RPS), and end the commitment to offshore wind, which is one of the most expensive resources out there.

This leads to Myth #2.

Myth #2: Data Centers Are Major Driver of Affordability Crisis

The following statement is in Executive Order No. 2:

“WHEREAS, as described above, the urgent need for more electricity generation to keep up with skyrocketing power demand from data centers is a major driver of the energy affordability crisis…”

This is interesting, because data center demand growth wasn’t a huge factor when prices started rising, and doesn’t explain why electricity rates in New Jersey have always been high and have been steadily increasing since 2018.

For example, in 2024, New Jersey had the 11th highest residential electricity rates in the country. This isn’t much different from 2020, when it had the 12th highest. Furthermore, when looking only at states within the PJM territory, New Jersey historically has the highest residential electricity rates among them, with the exception of 2023 when Pennsylvania surpassed it briefly.

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Notice that recent rate hikes in New Jersey started all the way back in 2018 before picking up in 2022.

The question we would ask Governor Sherrill: How can data center demand growth be a “major driver” of the affordability crisis in New Jersey when prices have been rising since 2018 while total electricity sales have been on the decline since at least 2010?

Clearly, something else is driving high electricity costs in New Jersey, and the executive orders do very little to address the real problems.

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Conclusion

With these two case examples in mind, it’s important to remember that just because politicians sing “energy affordability” and use it to promote policies, they may be doing the exact opposite.

In fact, the newly elected governors in Virginia and New Jersey really aren’t doing anything new to address affordability in their states. They’re rehashing old ideas and presenting them as new to address a problem that the old policies created.

Energy affordability is a real issue across the country and it won’t be solved with the same policies that brought it to our doorstep.

The truth of the matter is that America had a reliable and affordable grid, built up over many years and paid for by ratepayers, and this grid could’ve been providing inexpensive electricity for decades to come with minor additions to keep it running efficiently, relative to the massive buildouts we see today. We’ve squandered much of this grid, unfortunately, but the solution isn’t to keep going down the road of insanity even further. The solution is to begin the arduous process of building it back up again.

Sunk Costs by

The Great Unraveling by

In 1903, as part of his campaign against alternating current, Thomas Edison helped stage the public electrocution of Topsy the elephant at Coney Island.

Topsy was killed after her owners and handlers at Luna Park concluded she was too dangerous and too expensive to keep following a series of incidents, most notably the fatal injury of a handler in 1902. Rather than relocate her or carry out a quiet euthanasia, park management chose to turn her death into a public demonstration.

Today, five of the six New England states are pursuing a policy agenda that can fairly be summarized the same way: electrocute everything—mandating rapid decarbonization of the electricity sector while simultaneously requiring the electrification of home heating and transportation.

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Luckily, there are alternatives to this Pachyderm-like pain, and they are all laid out in a handy-dandy report published by a coalition of New England public policy groups1 entitled “Alternatives to New England’s Energy Affordability Crisis,” written by the team at Always On Energy Research.

Crunching the Numbers

Our report calculated the cost and reliability implications of “electrifying everything” in New England under four scenarios.

1. The Renewable scenario: Detailed in this article, this scenario attempts to meet rising demand using onshore wind, offshore wind, solar, battery storage, and existing nuclear and natural gas facilities.

2. Nuclear scenario: This scenario uses existing gas and builds new natural gas and nuclear plants to meet demand, with nuclear accounting for 90 percent of the electricity mix by 2050.

3. Natural Gas scenario: This scenario adds new natural gas plants and pipelines to meet rising demand, with gas accounting for 83 percent of generation in 2050 and existing nuclear accounting for 12 percent.

4. Happy Medium: This scenario adds nuclear and natural gas capacity, resulting in 47 percent nuclear, 47 percent natural gas, and 3 percent hydro and “other” in 2050.

According to ISO-New England, electrifying home heating and transportation will increase the peak demand to around 57 gigawatts (GW), up from the all-time peak of 28 GW. Unlike the current peak, the forecast peak in 2050 will be in winter, not summer, due to the massive need for electricity for home heating.

Our analysis praises the wisdom of New Hampshire because it is not pursuing an electrification agenda, so we downwardly revised our system peak demand to 52.5 GW to reflect the common-sense approach to energy policy taken in the Granite State.

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Meeting this 52.5 GW of future winter demand will require a massive increase in installed capacity for all scenarios. The Renewable scenario would require the most capacity, needing 225 GW to meet demand due to the intermittency of the wind and solar resources, while each of the other three scenarios could meet the projected peak with a little more than 60 GW, maintaining a healthy reserve margin.

This means the Renewable scenario required 3.75 times more capacity than the scenarios that used nuclear and natural gas to meet growing demand.

Building out this additional capacity for the region’s electrification efforts will be expensive, and the cost of electricity will rise for consumers in every scenario. However, the Renewable scenario takes the cake at an additional $815 billion, compared to $415 billion for the Nuclear scenario, $196 billion in the Happy Medium scenario, and just $107 billion in the Natural Gas scenario, as you can see in the graph below.

These costs will get passed on to ratepayers.

The Nuclear scenario would increase prices by 64.8 percent, the Natural Gas scenario by 13 percent, and the Happy Medium scenario by 26.5 percent. In comparison, prices in the Renewable scenario would increase by 126.4 percent, with massive impacts for New England families.

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In 2024, residential customers paid an average yearly cost of $2,100 for their electricity. Under the Renewable scenario, residential electricity prices would more than double by 2050, increasing New England families’ annual electricity costs to $4,610. Bills would rise to $3,339 annually in the Nuclear scenario, $2,302 in the Natural Gas scenario, and $2,569 in the Happy Medium scenario by 2050.

Despite the massive cost of the Renewable scenario, it is the least reliable of the four scenarios studied.

Outgoing ISO-New England CEO Agrees, Renewables Won’t Keep the Lights On

On December 31st, Gordon van Welie —who we are reliably told is a silver fox—stepped down as the President and CEO of ISO-New England. Prior to exiting the stage, he did not mince words about the reliability challenges being posed by public policies in New England.

In October, van Welie stated:

"We cannot operate the system in the wintertime without a dependable energy source that can balance the system when the sun doesn't shine, and the wind doesn't blow. I think policymakers sometimes lose sight of that fact.”

Mr. van Welie’s statements match very well with the results of our analysis. We found that of the four scenarios we studied—the Renewable, Nuclear, Happy Medium, and Natural Gas scenarios—only the Renewable scenario would have rolling blackouts, while the other scenarios easily meet the rising demand for electricity to power electrified home heating.

After stress-testing the ISO-New England across different weather years and wind and solar output, ISO-NE would experience a six-hour blackout in the Renewable scenario if the hourly wind and solar capacity factors matched those observed in 2019

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The other scenarios, however, would constitute what calls a “boring” electric grid with no reliability drama. But we ask our readers, where’s the fun in that?

Levelized Cost of Resources

We also conducted our “Always On” Levelized Cost of Energy Analysis to compare the cost of serving load with each energy resource in the scenarios studied.

As we detailed in our previous piece, attempting to meet this heightened demand in the Renewable scenario with offshore wind would cost $436 per megawatt hour (MWh), solar would cost $357 per MWh, and onshore wind would cost $240 per MWh.

Meeting the demand in the Nuclear scenario with small modular reactors and large advanced nuclear reactors would cost $253 per MWh and $185, respectively. It’s important to note that the increased cost of SMRs in the Nuclear scenario is driven by the fact that the units would not be utilized as often, as they are partly used to provide ramping ability to meet peak loads. This is shown in the “ramping” portion of the stacked bar chart.

In comparison, the Natural Gas and Happy Medium scenarios use traditional natural gas peaking resources, thus saving billions of dollars, and there is no need to ramp the SMRs because they can run at full speed.

Lastly, the costs of $46 and $47 per MWh in the Happy Medium and Natural Gas scenarios provide the lowest-cost power to the system.

Conclusion

Of course, each of these scenarios is expensive, so any common-sense individual might question the merits of attempting to electrify home heating and transportation at all, given the huge increases in electricity generation capacity that will only be used for five to six months per year.

We’re not optimistic that New Englanders will exhibit that much common sense. But our hope is that this report can restart the conversation about nuclear and natural gas pipelines in the Bay Area for the first time in a very long time.

1. Click that ❤️ for your chance to go on a date with Gordon van Welie

2. Share this piece for Topsy, who didn’t deserve all that ruckus.

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Gordon van Welie, President & CEO, ISO New England before the House Energy & Commerce Committee Subcommittee on Energy

ISO New England CEO says region needs firm dispatchable generation by S&P Global

EnergyMusings - January 14, 2026 by

“If a wind turbine is installed on the North Dakota prairie, but it isn’t spinning, does it even exist?”

- Anonymous

The prevailing narrative surrounding the power sector is that America’s grid is short of watts, and that we need to vastly increase our power generation capacity to avoid rolling blackouts and meet surging demand for data centers and reindustrialization.

Given the state of the discourse, it may be hard to believe that America has more installed electricity capacity on its grid than ever before. But it’s true. The problem is, so much of this capacity is from unreliable wind and solar facilities that provide almost no reliability value to the grid.

We first debuted this concept in our piece Shocking Betrayal: Why Progressives are Ditching Climate Laws and Dooming the Planet, but the implications are so significant that we concluded the graph merited its own larger discussion.

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“Capacity” Growth Exceeded Demand Growth

First, let’s set the stage.

The U.S. technically has more installed capacity on the U.S. grid than ever before, which has increased by 26 percent since 2004 and 12.5 percent since 2015. Meanwhile, electricity demand has only increased by 8.5 percent and 5.6 percent, respectively, during the same timeframes.

The result is that the country has more capacity (MW) per terrawatt-hour (TWh) of generation than ever before.

If “capacity” was the same across all resource types, this data would suggest that we should be more prepared than ever to meet growing electricity demand stemming from data centers and AI.

But we’re not. In fact, the opposite is true.

This begs the question: If the American grid has so much installed capacity on the system, why is it bracing for such severe supply shortages?

The short answer is that the capacity being built today—wind and solar—is far less reliable than the capacity it is replacing—coal and nuclear.

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Capacity Doesn’t Always Equate to “Reliable” Capacity

Put simply, wind and solar capacity is not the same as dispatchable capacity due to their intermittency. Intermittent generators are inferior to dispatchable resources for a number of reasons, but mainly because operators cannot control when they produce electricity and when they won’t.

We can forecast when they will or won’t fairly well (but not always), yet that doesn’t give us control over their production levels similar to traditional resources like coal, natural gas, oil, and nuclear. Not to mention, the entire point of forecasting wind and solar production is so that we can use other “backup” resources to supply demand when they aren’t able to, but this backup generation fleet is being retired more and more every year.

For example, the following chart shows that while intermittent resources like wind and solar have made up the bulk of net resource additions in recent years, firm capacity has been on the decline since 2011 with the exception of a slight rise in 2024.

The result is that the U.S. is now at pre-2005 levels of firm capacity on the grid at a time when electricity demand is projected to have the largest increases in over a decade due to data center and AI growth and electrification efforts.

So, even though the grid as a whole has more capacity than it did 20 years ago, the growth is made up entirely of resources that may be producing no electricity whatsoever when needed the most, and the system has roughly the same levels of firm, reliable capacity online as it did in 2004.

The result of this trend is obvious: supply shortages.

And it’s happening in pretty much every regional grid in the country.

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Regional Grids Show the Same Trend

The following regional charts are based on data from the Energy Information Administration (EIA) 860-monthly dataset from 2016 through 2025.

Data that includes each Regional Transmission Operator (RTO) only goes back to 2016, but the trend of diminishing dispatchable capacity can still be seen—and this is why despite every RTO having the highest installed capacity than ever before, the NERC Long-Term Reliability Assessment (LTRA) shows that many of them at elevated risks of capacity shortfalls in the near future, including PJM, MISO, SPP, New England, and ERCOT.

PJM

Capacity prices in PJM recently hit record-setting levels, at $333/MW-day, after failing to reach reliability targets.

And it’s no wonder.

Despite having more capacity installed than ever before, reliable capacity in PJM has actually decreased by 2 gigawatts (GW) since 2016, from 198 GW to 196 GW, and is down 6.8 GW since firm capacity peaked in 2018. This comes at a time when peak demand hit new records in 2025 at over 160 GW, according to data from the EIA Hourly Electric Grid Monitor.

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Since 2016, the majority of capacity growth in PJM has consisted of solar and gas. However, natural gas additions have failed to keep up with retirements from coal and oil generators, and it’s impossible to maintain a reliable system in the face of growing demand when relying on solely intermittent generators.

NERC explains that state and federal environmental regulations and mandates are mostly responsible:

PJM’s review of recent policies (e.g., state laws and federal environmental initiatives) indicates over 32 GWs of potential deactivations through 2034. The pace of retirements is being driven in large part by these state laws and federal environmental initiatives that create a clear near-term, date-certain requirement for generation to comply or retire. Conversely, there are multiple mandates with renewable portfolio standards (RPS) that account for the majority of over 150 GWs submitted projects.

MISO

The situation in MISO is even worse than PJM.

Once again, even though the RTO has more capacity online in 2025 than any year prior, firm capacity in MISO has dropped by over 22 GW since 2016 and has been replaced by 35 GW of intermittent wind and solar resources.

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Natural gas additions in MISO of about 5 GW haven’t come close to replacing the 24.5 GW of coal retirements since 2016. Instead, wind and solar are being used to directly replace firm capacity on the MISO system and, as shown in the graph, MISO increasingly has less reliable capacity to serve peak load.

NERC explains how this trend is leading to supply issues in MISO, “Uncertainty around new resource additions and existing generator retirements results in resource adequacy risks.”

NERC continues, explaining that this trend is expected to continue:

The departure of MISO’s coal fleet has continued with a reduction in capacity of around 6 GW in the past year, and a projected reduction of a further 12 GW over the next five years. Solar continues to rise in capacity contributions with a growth of 1,200 MW since the 2023 LTRA and growth of 3,200 MW in the first year of the study.

This is bad news for everyone within the MISO territory.

SPP

SPP is similar to PJM in that it has had a net drop of firm capacity of 2.6 GW since 2016, which has been replaced with nearly 21 GW of intermittent wind and solar facilities.

Similar to MISO, this trend is expected to get worse, and SPP is becoming morereliant on intermittent resources to meet peak demand.

In fact, it is now so reliant on wind resources to maintain reliability, NERC warns that low wind speeds may result in blackouts in the near future if disptachable capacity doesn’t sufficiently replace an anticipated 8 GW of coal closures slated for retirement.

“There are over 8 GW of coal and gas-fired generators that have indicated they plan to retire over the next 10 years in SPP. Without sufficient dispatchable generation, SPP can experience energy shortages when output from wind resources is low.”

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ERCOT

On the capacity side, ERCOT shows a similar trend to the rest. Total capacity is at record highs, yet firm capacity has decreased slightly.

Unique to ERCOT, however, is that it isn’t just anticipating future load growth—it’s been experiencing huge load growth for several decades. Since 2016, peak demand has grown by over 12 GW, or by over 17 percent.

This means ERCOT has built solely intermittent resources, and more recently battery storage, to meet a 17 percent load growth over the last 10 years. The result is that ERCOT is entirely dependent on good weather conditions to meet peak demand.

For example, Monthly Operational Resource Adequacy (MORA) reports consistently show that ERCOT doesn’t have enough dispatchable capacity to meet peak load during average weather conditions, even when including energy storage, as shown below. In the most recent January MORA, load is expected to be 77,387 MW, and ERCOT anticipates 74,176 MW of available dispatchable capacity. The rest is expected to be supplied by wind and solar resources.

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Conclusion

These aren’t the only regional grids that show this trend.

The same characteristics exist in CAISO, NYISO, and ISO-NE: total capacity is at record highs, capacity growth consists almost entirely of intermittent and less reliable resources, and firm capacity remains flat or continues to decline.

Most grids are now playing catch-up, attempting to build new natural gas facilities and restart nuclear plants after realizing they cannot meet growing demand with hopes and wishes alone.

But this realization needs to go even further if we want to maintain a reliable grid for future generations.

The reality is that we have spent years building essentially worthless capacity, throwing away money and the backbone of our economy along with it. The failure by policymakers and grid planners has been so severe that serious energy policy proposals are increasingly centered on preventing energy-intensive industries from growing, rather than finding ways to support and integrate them.

This is not the way energy policy should operate. Unfortunately, decades of destructive energy policies are now forcing degrowth (or stagnate growth) solutions upon us because we don’t have the capacity to take on energy-intensive industries, and we may not have a choice.

Washington's Self-Inflicted "Energy Burden" by

Cal-Affordability crisis is not an accident. It is the product of failed leadership. by

A few recent energy headlines by

2025 marked an incredibly successful year for us at Energy Bad Boys and Always On Energy Research (AOER). Today, we’re going to give you a sneak peek at what’s to come in 2026 and reflect on some of the highlights of 2025.

As always, thank you to all of our Energy Bad Boys readers for their ongoing trust in our content. We’re incredibly grateful that you spend (almost) every Saturday with us.

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2026: Onward and Upward

One of our key focuses in 2026 will be data visualization. We already do the hard work of digging through primary sources and assembling datasets; why not present them with interactive graphs, maps, and charts so they are more likely to be shared by our readers?

As an example, we made the video below of a bar chart race with Flourish. It shows the All-Sectors electricity prices for each state from 2001 through August of 2025 as they change over time. As you can see, there is some sorting that takes place between liberal and conservative states during this time frame. Take a look!

These types of graphics, in addition to the maps and graphs we’ve recently made with Datawrapper, represent a leveling up of our ability to communicate with the general public and provide policymakers with useful and shareable information.

More to come in 2026!

Speaking of Useful Information

We are also very excited to announce that will be joining the AOER team. In addition to being an accomplished policy analyst and a terrific writer (check out her Substack here), she has a background in computer programming and data science, and we are excited to leverage these skills to (hopefully) automate some of the manual data-collecting work we do with EIA forms, utility filings, and other datasets.

Ideally, we’ll be able to build interesting dashboards like this one so we can compare things like electricity prices across utilities over time.

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We’re also looking forward to expanding the analyses we can conduct with our S&P Global Capital IQ subscription to deliver more deep dives into utility finances and broader power-sector trends.

Projects

Right now, we are working on some fun projects that will carry us through the first quarter of 2026, including:

• A Levelized Cost of Energy analysis for the state of Indiana on behalf of Reliable Energy Inc. The project compares the cost of new generation to the existing fleet as Indiana seeks to navigate affordability concerns and new data center demand.

• Rate case intervention with our friends at the Arizona Free Enterprise Club. We will be helping with the analysis of the Arizona Public Service and Tucson Electric Power rate cases.

• The Social Cost of Blackouts: A deep dive into the economic impact of power outages and the time value of electricity.

• Blue States, High Rates will be an ongoing project for us.

• What’s driving costs in Wisconsin? We’ll be doing a policy brief on the factors increasing electricity prices in Wisconsin, and draw from our previous work at Center of the American Experiment for a forecast of things to come.

If you or your company would like to work with us for your energy analysis needs, please reach out at isaac@aoenergy.org.

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The Best of 2025

We completed several projects at AOER in 2025. They included:

• A report with the Commonwealth Foundation in Pennsylvania modeling the cost of Governor Shapiro’s proposed renewable energy mandates and PA’s participation in the Regional Greenhouse Gas Initiative (RGGI). The report was cited by Pennsylvania lawmakers and helped get legislation passed removing Pennsylvania from RGGI this fall.

• Reliability and cost modeling for the Prime Mover Institute on the EPA’s proposed rules to repeal Biden-era regulations on greenhouse gas emissions from power plants. We argued the administration was massively undercounting benefits because it was simply reversing many of the Biden administration’s assumptions. We received several emails stating our comments were the best the readers had seen in the docket.

• An analysis of the cost savings of phasing out wind and solar subsidies in the One Big Beautiful Bill Act for Alex Epstein.

• An update to our 2024 report on the cost of decarbonization with our friends in New England. The report should be out in January.

• An analysis of the enormous cost of green hydrogen in Colorado for the Independence Institute.

• A report calculating the tax revenues of coal, natural gas, oil, wind, and solar for the Wyoming Liberty Group.

• Calculating the cost and reliability implications of the Arizona Public Service IRP for the Arizona Free Enterprise Club.

• Expert witness testimony involving the certificate of need for a proposed solar project in Cerro Gordo County, Iowa.

• Blue States, High Rates.

We haven’t written summaries of all of these projects on Energy Bad Boys. That’s in part because we like using this platform to explore new topics, because eventually it probably feels like too much self-promotion, and, most importantly, because we feel like reading summaries of our reports probably gets repetitive for our readers, and we value your time and attention spans.

Let us know in the poll below if you want more summaries, fewer summaries, or if you’re happy with the balance we’ve struck so far. No post next week. We’ll see you in 2026.