Tag: the grid

Synergy of Wind & Solar Generators in Australia’s NEM

In Australia’s National Electricity Market, wind and solar are often described as complementary generators: solar produces mainly during daylight, while wind can generate during the night and in periods when solar output is low.

But the word “synergy” can be misleading. Complementarity does not mean reliability.

From Watts Up With That?

Richard Willoughby

Summary

This article analyses one year of wind and utility solar generation data from Australia’s National Electricity Market (NEM). Using generation and curtailment data from OpenNEM, it estimates the storage requirements needed to firm wind and utility solar generation, examines the cost trade-offs between battery storage and generation overbuild, and extends the assessment to pumped hydro, household battery subsidies, and the economics of grid-scale storage. The author concludes that:

  • Wind and solar show some complementary behaviour (“synergy”) when combined.
  • A 16-hour battery appears to provide the lowest overall system cost based on the stated assumptions including current ratio of wind to utility solar.
  • Supplying peak NEM demand using only wind, solar and batteries would require substantial additional generation and storage capacity.
  • Based on the stated cost assumptions, the resulting levelized cost of electricity (LCOE) would be twenty times higher than conventional lignite fired generation costs achieved in 2003.
  • Recent market developments reinforce the author’s view that large-scale wind, solar, batteries and pumped hydro do not currently offer favourable economies of scale in the NEM.
  • The Discussion argues that Snowy Hydro’s useful storage volume is constrained by its relatively low generating capacity, while home battery subsidies and expanded small-scale solar eligibility are shifting value away from grid-scale batteries and pumped hydro.
  • The author concludes that a fully renewable NEM remains economically impractical under current conditions.  Rooftop solar and behind-the-meter batteries are more economically viable than centralised “renewables” projects for the emerging de-industrialised economy.

Wind & Solar Generation in the NEM

Australia’s National Electricity Market (NEM) supplies 86% of the Australian population through a single interconnected grid.  The registered wind capacity is 13.46GW and the registered utility solar capacity is 10.71GW.

In the year to 1st August 2026, wind generated 36.6TWh and utility solar produced 19.8TWh.  The recorded daily generation is displayed in Chart 1.

The key observations from Chart 1 are that the wind varies considerably day-to-day with multiple consecutive days of low output while the utility solar has smaller day-to-day variation but the annual variation is clearly evident.

OpenNEM also records the estimated curtailment of both wind and utility solar making it possible to assess the true potential of these two power sources.  Chart 2 shows the cumulative generation less the daily average over a year.

Chart 2 actually shows what the installed capacity is capable of if there was sufficient storage to absorb all excess and then release it as required.  The average daily output for wind would be 111GWh and would require a battery capacity of 1700GWh.  The existing utility solar would be able to supply daily average of 65GWh when supported by a 2600GWh battery. 

Trade-off of Battery Capacity and Generation Overbuild

At present battery costs, it is more economic to overbuild the generation to reduce the size of the battery.  Chart 3 shows the charge state of batteries with 24-hour storage capacity working independently for wind and solar.

In this situation, the existing wind could support an average daily demand of 48GWh while utility solar could support 34GWh per day.

Chart 4 shows the result of combining the sources of generation while still using a 24-hour duration battery.

The combined daily demand that can be served is 99GWh.  So the two sources exhibit synergy; enabling the combined output to be 20% higher than the sum of the individual outputs. 

The Minimum System Cost Battery

The current costs for the key components of a battery firmed wind and solar grid are:

  • Wind Turbines – AUD3.5bn/GW
  • Utility Solar – AUD1.5bn/GW
  • Battery AUD0.5bn/GWh
  • Transmission Lines – 30% additional capital for generators

Using these current estimates and the demand pattern with the existing wind and solar generation, it was determined that a 16-hour battery gives the lowest overall system cost.  Chart 5 indicates that such a system could meet a daily demand of 93GWh.

100% Battery Firmed Wind and Solar System

The highest daily demand was 728GWh so the existing wind and solar generation would need to be scaled 7.8 times to get from 93GWh per day to 728GWh. This gives a system requirement of:

  • Wind Generator Capacity – 105GW
  • Utility Solar Capacity – 84GW
  • Battery Capacity – 485GWh

Levelised Cost of Energy from Wind and Utility Solar

Using the system cost components, the total system cost comes to AUD958bn.  Applying a cost of capital of 7%pa and O&M cost of 2% of capital per year over a 20 year life requires an annual income of AUD110bn.  Considering the annual demand totalled 220TWh, the average unit cost would be AUD500/MWh.  

This cost estimate is based on further simplifying, but optimistic, assumptions such as:

  • 100% round trip efficiency for the battery.
  • Battery systems can support most FCAS requirements while any inertia requirements are covered by the 30% transmission margin.
  • Market management costs are in addition to the LCOE calculated here.

100% Battery Firmed Utility Solar

The existing utility solar can produce 34GWh per day with a 24-hour battery so it would need to be scaled 21 times to meet the peak daily demand with a purely solar/battery system.  This reduces the capital cost to AUD920bn and unit cost to AUD478/MWh.

Discussion

The mechanism that encouraged weather dependent generators onto the grid was legislated in 2000 in Australia.  The price impact was noticeable after 2003 when lignite fired generation was selling for AUD23/MWh.  Lignite generation now sells for AUD85/MWh because it is being cycled rather than operating at full capacity continuously but remains one of the ESSENTIAL sources of generation so can charge high prices when wind and solar are low.

Despite there being synergy with wind and solar generation, the high cost of wind generators in Australia makes them uneconomic against utility solar. And utility solar is uneconomic against rooftop solar because rooftops have dedicated demand. The low financial close on projects under the Capacity Investment Scheme indicates that investors are faced with actual costs exceeding estimates thereby making projects uneconomic despite the government guaranteed return on estimated cost.

Snowy Hydro pumped storage provides a storage capacity of 350GWh but its generating capacity is limited to only 2GW.  On a 16-hour basis, it only offers 32GWh.   So at the estimated cost of AUD42bn it works out at AUD1.3bn/GWh – more than double the current battery cost but it should outlast some five sets of battery using current technology.

It is noteworthy that in Q2 2026, the 240MW Shoalhaven pumped hydro energy storage (PHES) earnt just $1.3M for the quarter.  There is now a clear decline in income for PHES in the NEM since the introduction of the Cheaper Home Battery Scheme (CHBS) from July 2025 per Image 1 extracted from the AEMO report.  The CHBS scheme provides a 30% subsidy for battery purchases resulting in 11GWh being installed in the past twelve months; much faster than grid scale projects and households now own most of the battery capacity on the grid with three more years for the program to run.

A further recent observation is that the arbitrage on grid scale batteries has collapsed from $360/MWh a year ago to $60/MWh in the latest quarter.  So the CHBS has now made grid scale battery installations uneconomic.

As further evidence of the economic reality of negative benefit of scale for wind, solar and batteries, the Federal Government has made a 10-fold increase in the small-scale solar limit; taking it to 1MW from the existing 100kW.  That means shopping centres, hospitals, schools, etc can now gain subsidies for large solar/battery installations. 

Conclusions

Building a 100% “renewables” grid for the Australian NEM remains firmly in the realm of fantasy for the present time.  Achieving the first 50% has caused a 4-fold increase in base load cost and the next 50% will cause another 4-fold increase. 

Snowy Hydro pumped storage will only enable one more coal fired power station to be retired providing wholesale demand continues to slowly decline or is static.  Its power rating is inadequate to fully utilise its storage capacity.  If economics prevailed over insanity, the Snowy Hydro pumped storage project would be stopped.  Its earning potential at the present time is just $40M per year or 1/1000th of its capital cost.  The potential income will not even cover its operating and maintenance cost.  It is a comprehensive waste of money; albeit the Labor Party receive generous donations from the unions to keep the money pit producing.

Wind, solar and batteries do not offer any economy of scale.  That had previously been observed with the rapid uptake of rooftop solar in Australia and the steady decline in the wholesale market.  Home batteries are now making the same point as the grid scale batteries and pumped hydro lose their market.

The de-industrialisation of the Australian economy continues per Image 2 with quarterly volume down 0.5% year-on-year as rooftops exceed any growth.

The Author

Richard Willoughby is a retired electrical engineer having worked in the Australian mining and mineral processing industry for 30 years with roles in large scale operations, corporate R&D and mine development.  In the early 1990s he represented large customers on the first market system committee for the Australian National Grid.  A further ten years was spent in the global insurance industry as an engineering risk consultant where he developed an enduring interest in natural catastrophes and changing climate.

Seconds from disaster, Britain was forced to beg France for more power

Grid frequency (normally ~50 Hz) dipped dangerously low—to 49.656 Hz around 8pm—risking instability or blackouts if it fell further. National Energy System Operator (NESO) engineers contacted their French counterparts at RTE urgently. Within minutes, power flows reversed on interconnectors, delivering nearly 2 GW from France to stabilize the system. An official market notice followed shortly after.

From NOT A LOT OF PEOPLE KNOW THAT

By Paul Homewood

It was much worse than we thought!

From the Telegraph:

Seconds from disaster, Britain was forced to beg France for more power

Experts say the events of June 23 prove the UK’s energy network is dangerously exposed

As they sat down to watch England’s World Cup showdown with Ghana, millions of football fans were oblivious to the crisis unfolding on Britain’s power grid.

It was June 23 and the country was sweltering under a heatwave, prompting many to crank up fans and air conditioners at home.

With large numbers also glued to their televisions late into the night, it meant demand on the electricity system was unusually high.

What the fans didn’t know, however, was that in a control room in Reading, engineers at the National Energy System Operator (Neso) were sweating to keep the show on the road.

At 17 seconds past 8pm, just an hour before kick-off, the crisis reached its nadir. Disaster was only averted after grid bosses begged their French counterparts for help over the phone.

The story is being seen by some experts as the clearest example yet that Britain’s power network is exposed.

“It’s a warning, and one we’re going to have to learn from,” says Ben Watts, an independent energy analyst. “I think everyone accepts we were very close to having a problem, but it didn’t quite get there.”

Neso also faces whistleblower allegations – which are being independently investigated – that bosses sought to cover up the evidence of instability on June 23.

The grid operator has insisted the system worked properly throughout. That is one possible telling, say experts. Another is that the day was only saved thanks to sheer luck and goodwill from the French.

So who is right? And what happened?

Full story here.

According to the Telegraph:

With 8pm approaching, Britain’s 3.3GW battery fleet was running low on power and the amount of available spare gas capacity had dwindled to just 80MW in the South.

At 7.50pm, the frequency dipped below normal operating levels again and at 8pm precisely it hit 49.656Hz – the lowest level observed this year.

It was enough to prompt Neso to plead for emergency help.

Just before 8pm, engineers in the British control room picked up the phone and called their counterparts at RTE, the French grid operator. An official market notice was then published at 8.01pm, but gave no detail.

Within minutes of Neso’s call, grid operators in Paris swung into action.

Between 7.55pm and 8.05pm, three French interconnectors changed direction and started funnelling nearly 2GW of power back into Britain.

With this, the grid’s frequency rapidly climbed back into the comfort zone and didn’t leave it again for the rest of the evening. France had saved the day.

Kathryn Porter commented:

“There was no reserve left,” she wrote on social media. “This is deeply worrying, because if we’d lost a major generator that evening it could have been game over particularly with so many grid boundaries running over capacity.

“It looks like Neso ran the grid past its limit that evening and was saved by two things: France delivering extra megawatts and nothing breaking during the critical evening period.”

Battery Storage For Grid Backup: Better Keep Working On It

Advocates of generating electricity mostly with intermittent wind and sun, when challenged on how they would deal with a calm night, are always ready with the obvious answer: energy storage. Just get some batteries, store up excess power from the windy mid-days, discharge as needed, and everything will work out.

From The Manhattan Contrarian

By Francis Menton

Advocates of generating electricity mostly with intermittent wind and sun, when challenged on how they would deal with a calm night, are always ready with the obvious answer: energy storage. Just get some batteries, store up excess power from the windy mid-days, discharge as needed, and everything will work out.

Unfortunately, the advocates never acknowledge that the problem of making an electrical grid work 24/7/365 with mostly wind and solar generation is much more difficult than just storing power from the day to discharge that night. Both wind and sun are subject to regular “droughts,” just like rain. There can be many consecutive days, or even weeks, of combined low wind and sun; let alone the entire winter has a lack of sun, and both summer and winter have less wind than spring and fall. Calculating how much energy storage will suffice to get through even a year of average wind/sun variability is a straightforward exercise, yielding an answer of as much as 1000 hours of average consumption. Meanwhile, naive politicians (those in New York being Exhibit A) regularly get duped into buying a few hours or tens of hours worth of batteries for grid backup, spending billions of dollars on amounts of storage that will be almost useless for backing up a primarily wind/sun grid.

I first wrote about this subject way back in 2018, and have had many follow-up pieces since. The conclusion of my pieces has been that to obtain sufficient battery storage to back up a primarily wind/sun grid using current lithium-ion battery technology, and even assuming best case future cost reductions and economies of scale, would cost the full GDP and more of any jurisdiction that makes the effort.

Well, who says you can only use lithium-ion technology? The massive Biden-era green energy handout statutes (e.g., the “Inflation Reduction Act”), together with green energy enthusiasm generally, have brought forth a gusher of entrepreneurialism looking for new, better and cheaper energy storage systems. Recent comments on some of my posts, as well as those of daughter Jane over at @janementonnyc on Instagram, have advocated for two new technologies of energy storage as the solution to the intermittency problem. Those two are flywheel batteries, and iron-air batteries. Could either of those really work?

As background to discussion of those two specifically, I suggest thinking about the model of the storage of drinking water. New York City stores water in a network of reservoirs located in upstate New York. The City’s water consumption is approximately 1 billion gallons per day. The storage capacity of the reservoirs is approximately 550 billion gallons, that is, approximately 550 days, or more than a year and a half of consumption. The amount stored in the reservoirs fluctuates over the course of a year, and generally drops over the summer and into the fall, but it rarely gets below about 70% of capacity, or about 380 billion gallons. And in years with serious droughts, the storage can fall below 50% of capacity, and even down to 40% of capacity. A storage level of under 40% of capacity has only happened once in my lifetime, which was about 60 years ago. In other words, most of the storage capacity is there to guard against a worst-case drought, and much of the water remains in storage for decades on end to guard against that event. Fortunately, a simple reservoir has the capability to do that.

An electrical grid without full dispatchable backup needs the same kind of storage capability. The fact that a group of generators can produce the same number of MWhs of energy in a year as the average amount demanded means little unless the energy can be matched minute by minute to the demand. To meet that criterion, a storage system must be able to store the energy from summer to winter, or from spring one year all the way to spring the next year. Preferably, there should be an ample balance stored for the long term to guard against a worst-case wind/sun drought that may occur only once a decade.

By the way, it is by no means clear that lithium-ion batteries have this level of capability. But for today, let’s consider the technologies advocated by our commenters, flywheel and iron-air.

Flywheel batteries. Flywheel batteries have lots of advantages. For example, they can discharge a very high percentage of the energy originally stored in them (90-95%), and can be charged and discharged potentially thousands or even tens of thousands of times without seriously degrading. Moreover, they can ramp up and down quickly to replace generation from intermittent sources; and they have spinning inertia, which wind and solar generators do not, and which is badly needed for grid stability.

But unfortunately flywheel batteries have very high rates of what is called “self-discharge,” that is, dissipation of the stored power over time. According to this source (something called Permanent Energy), many flywheel batteries lose as much as 12.5% per hour, and even the best ones lose about 5% per day. Other sources give me similar answers. In other words, energy stored in a flywheel battery will be long gone a month later, even if never called on. Flywheel batteries may have many uses, but for purposes of backing up the grid against any serious wind/sun drought, they are worthless. Oh, and they are expensive — currently costing in the range of $400/kWh, which is more even than lithium-ion batteries and translates to many trillions of dollars to buy amounts useful for full grid backup.

Iron-air batteries. This is a type of battery that uses only the simplest and most common of materials — iron and air. The process of storing and discharging energy takes place by repeatedly rusting and unrusting the iron. It turns out that you can store a lot of energy that way. It’s not subject to exploding or catching fire. And it’s cheap: proponents claim that they will be able to achieve a price of $20/kWh, which is a small fraction of the current price of lithium-ion batteries (~$300/kWh). So what could possibly be the problem?

Again, self-discharge is a killer. Current iron-air batteries lose about 2-5% of their stored charge per day. At that rate, all the stored charge will be gone in two months, if not one. Maybe the rate could be improved, but it would need to improve by multiple orders of magnitude to make these batteries even a little useful for large-scale grid backup against worst-case droughts.

And then there are a few other problems. Iron-air batteries can only return about 50% of the energy stored; the rest is lost. And they can only discharge about 1% of the stored energy per hour. That means that they are incapable of ramping up and down quickly to back up the intermittent wind and sun.

Now I’m not at all saying that these two sorts of batteries cannot be useful in certain applications. For example, flywheel batteries appear to be very useful to supplement diesel engines to operate heavy cranes. The cranes go for long periods at low energy, and then have a big surge in power demand when they suddenly lift a heavy load. Pairing a flywheel battery with the diesel engine can cut the size of the needed engine by as much as half.

But why anybody, let alone our commenters, thinks that these sorts of batteries are the answer to grid backup for wind/sun generation, I do not know. Maybe some day. Meanwhile, keep working on it. As I have said before, if someone figures out a battery technology that has the needed capability and is also cost-effective to make a grid work with wind/solar generation, I will be the first to applaud.

The Real Grid Crisis Is a State Policy Problem Dressed Up as a Market Failure

There’s a critique of PJM making the rounds: PJM is too big. There are too many state interests at play, and PJM doesn’t have the ability to function cohesively or quickly enough. FERC even scheduled a governance technical conference this month to examine whether PJM’s stakeholder structure can move fast enough to respond to demand. The reality is that policy disagreements at the state level are dressed up as a procedural defect with the grid, opening the way for critics to point their reforms at the wrong target.

From Watts Up With That?

By Todd Snitchler

There’s a critique of PJM making the rounds: PJM is too big. There are too many state interests at play, and PJM doesn’t have the ability to function cohesively or quickly enough. FERC even scheduled a governance technical conference this month to examine whether PJM’s stakeholder structure can move fast enough to respond to demand. The reality is that policy disagreements at the state level are dressed up as a procedural defect with the grid, opening the way for critics to point their reforms at the wrong target.

Disagreements at the state level are just what you’d expect, pitting those that generate enough power to export against those that depend on imports. Pennsylvania is PJM’s energy workhorse, shipping out roughly a quarter of everything it generates. Illinois, West Virginia, and Michigan also produce more than they consume. The others – Virginia, Maryland, New Jersey, and Delaware – are net importers, and increasingly so as data centers expand across their footprints.

Exporters like Pennsylvania that are rich in nuclear, gas, and coal generation have fundamentally different interests in capacity pricing and transmission cost allocation from an importer state, which has restricted natural gas development, leaned hard into renewables, or joined an ambitious emission reduction program. When Virginia pulls in more expensive power from its neighbors, or when Maryland absorbs double-digit rate hikes, that isn’t a governance failure – it’s the market doing its job by revealing the cost of divergent state policy preferences (and thus resource access).

These state policy preferences are then lobbed at the market and its participants to respond to, whether by prematurely retiring generation, relying on tax subsidies, or simply building generation that is more expensive per megawatt when compared against traditional baseload fuels.

PJM is actively working to continue the evolution of the market to meet the demand of today and the future. It has cleared more than 60% of its interconnection backlog under a reformed study process and opened a new study cycle this spring in partnership with Google to apply AI to speed up the review process. A separate PJM program, the Reliability Resource Initiative, pulled in more than 11,000 MW of new projects that could come online quickly. PJM has also adjusted its review processes to allow more wind, solar, and storage to compete directly in the capacity auction. It’s even accepted a price collar through 2030, demonstrating that it is willing to make short-term adjustments in response to concerns by state executives.

More than 46,000 MW of approved projects – over a quarter of PJM’s existing capacity – already hold the right to build but are unable to move forward. Some 37,000 MW of PJM-approved generation can’t even break ground at all because of state and local permitting fights. At the same time, state policy mandates have pushed working plants into early retirement, further tightening supply from the other end. The same governors demanding faster action are often the ones holding the permits and slow-walking the buildout of energy infrastructure while forcing closures of dispatchable power.

PJM is not too big. It has demonstrated time and again that it can run a competitive power market and ensure the reliable transportation of power across 13 very varied states and the District of Columbia. It’s been successfully doing this for more than 30 years, delivering $5 billion in savings annually to customers, just as it was designed to do. It’s accelerated the queue and kept the lights on. What the market cannot do is permit projects or draft legislation. States must recognize their role in restricting the full benefits of the market.

Asking PJM to continue navigating these policy issues in the same manner – trying to respond to all of them – is a recipe for disaster. The states are absolutely responsible for chucking icebergs into the path of this ship, and if it goes down, they’ll have themselves to blame for the aftermath.

Todd Snitchler is President and CEO of the Electric Power Supply Association (EPSA).

This article was originally published by RealClearEnergy and made available via RealClearWire.

The Chance of Blackouts

“What I know about electricity is that when I flip the switch the lights come on.” Some variant of this statement is what I hear from people when a discussion involves electric energy service. People do not understand much about their electric service – generally can’t even fathom their electric service bill. One friend of mine, a scientifically trained person, responded to me when I referred to Kilowatt-hours by saying, “I don’t understand those units at all.”

From Watts Up With That?

Kevin Kilty

“What I know about electricity is that when I flip the switch the lights come on.” Some variant of this statement is what I hear from people when a discussion involves electric energy service. People do not understand much about their electric service – generally can’t even fathom their electric service bill. One friend of mine, a scientifically trained person, responded to me when I referred to Kilowatt-hours by saying, “I don’t understand those units at all.”

What is truly misunderstood here is that the lights coming on is only an expectation that has become a certainty in people’s minds because our electrical generation and distribution system, or systems, have become exceptionally reliable. Utilities often strive to reach a reliability often stated as less than 0.1 days of outage per year.[1]  A mere 0.027% of unserved demand.

Numerous places now have planned outages organized to prevent wildfires. This occurs in California, Colorado, and even Wyoming.[2] If analysis by the North American Electrical Reliability Council is to be taken seriously, unplanned outages may soon become common in much of the U.S. Figure 1 is a map, taken from the NERC Long Term Reliability Assessment, published in January 2026. It shows nearly half of the continental U.S. being at high risk of blackouts, beginning  variously from 2028 to 2030 and continuing for five years or thereabouts.

Figure 1. From the North American Electric Reliability Council 2025 Long Term Reliability Assessment.

Reasons for these elevated blackout risks are commonly that demand in each region is rising faster than new supplies can be procured.[3] These are risks related to energy adequacy and are not the only risks that the electric service system faces, but are the easiest to quantify.[4]

I live in the region shown in Figure 1 as WECC Basin. It is effectively a region served by two utilities – Idaho Power Company and PacifiCorp’s subsidiary, Rocky Mountain Power (RMP). The two face very different adequacy risks. Idaho Power serves a territory in which there has been a surprising surge in demand from an unforeseen surge in migration largely from California. It faces future risks as well from people in Oregon who’d feel virtuous if they could get the Federal government to breach dams on the lower snake river – dams which supply some 70% of Idaho’s hydropower.

Rocky Mountain Power’s problems stem from population growth in Utah and concomitant A/C demand in summer, along with increased industrial demand in Wyoming. But unmentioned is its long term commitment to replacing coal and gas with wind and solar.[5]

How does renewable power perform?

In March 2025 our Public Service Commission (PSC) had scheduled a hearing on the latest general rate case of RMP. The requested rates would raise power bills by something like 17% atop rates that had already risen by nearly 21% in the previous rate case in 2023. Even though RMP and all intervening parties had reached a stipulated settlement beforehand, I attended the meeting armed with pertinent data.

When a Rocky Mountain Power official was asked about why they were building the Rock Creek I and II wind power facilities, which were a large part of the reason for this rate increase, her answer was “to guarantee safe and reliable power to our customers.” This pat answer, meant only to reiterate what everyone knows to be the goal of utility regulation, caused me to show data undermining the “reliable” part of the claim.

During February 2025 there were multiple periods in which wind power was almost non-existent.  In particular, during a 15 hour stretch of low wind on February 11 wind power sagged to 46MW during the dark hours with zero solar energy. This represents a capacity factor of 0.8%!

I further showed that the Western Area Power Administration, from which RMP was importing power during these low-wind periods, had no wind power available either. The bulk of the PacifiCorp East Balancing Area (PACE) was being carried by coal plants, many of which, I emphasized, were soon to be shuttered.  I concluded by saying “Someone needs to address this issue, and soon.”[6]

One of the commissioners asked if the situation I just had shown to the meeting occurred also in other times of the year. I knew that it was even worse in summer and that early autumn, October for instance, could be very difficult for generating wind energy.

In preparing for a radio interview on this topic of reliability last autumn, I decided to quantify how often energy from wind and solar vanishes. I took 2025 data from January 1 to September 30 and determined how often wind energy would dip below 10% capacity factor during the dark hours – hours when solar was zero.[7] Table 1 nearby shows the result.

Table 1. Number of periods of less than 10% wind energy capacity factor during dark hours in the first 9 months of 2025.[7]

MonthJanFebMarAprilMayJuneJulyAugSept
Occurences45581113131917

I was actually surprised to see a total of 95 such periods, and to see how concentrated they were toward high summer. This is exactly the time period when A/C demands are greatest in Utah (and eventually in southwestern Wyoming when planned data centers become functional).

Why use 10% capacity factor?

It is very difficult to get utility spokespersons in public hearings to state clearly what they are thinking. Their applications to the PSC for adjusted rates and permission to build are huge documents and not necessarily clear either. The IRPs, which should inform us clearly of their future intentions, do not fulfill that expectation if they aren’t vetted thoroughly. The IRPs of both Idaho Power and PacifiCorp are not vetted seriously by the PSC, and as a result are just political documents meant to show that they are towing the politically correct lines – abandoning fossil fuels.  

In January 2023 I attended a hearing at the PSC where PacifiCorp was asking for permission to build the Rock Creek I and II wind energy facilities.[8] The discussion was focussed on the need for this facility being that PacifiCorp faced a looming 1,800MW capacity shortfall. This wind plant was said to be needed to close that capacity gap. The discussion persistently referred to the nameplate rating of the plant (590MW) and several times I made public remarks that nameplate rating is the wrong metric for making decisions; that the actual output of the plant could be only 200MW as annual average and at times would surely be zero.

When one commissioner asked the PacifiCorp representatives how much of the 1,800MW capacity gap would they estimate the 590MW plant would cover, PacifiCorp answered as low as 60MW. In other words, PacifiCorp views wind energy without battery backup as being worth

about 10% of its nameplate; a value so close to the Effective Load Carrying Capacity (ELCC) of a wind or solar power system that, in the absence of other guidance from the utility, we should just assume ELCC is what they intend. I should also point out that 10% capacity factor of wind in the dark periods of a day, and considering the mix of wind+solar in PACE, amounts to a capacity factor for renewable energy in total of less than 6%.

There are several important implications to draw from this. First, the stated 60MW useful capacity of this wind plant should have drawn additional questions from the PSC, but did not. The implication of this is that to close an 1,800 MW capacity gap with wind plants like Rock Creek I and II would require 30 of them; costing $27 billion and occupying 4,000 square miles of land. Clearly a bizarre conclusion.

A further implication is that if we view this 10% capacity factor in reliability terms, there are periods on one-third of days, mainly concentrated in summer, where an adequacy shortfall would occur and have to be covered by some other means – lean on your neighbor, batteries or just shut off the power.[9]

Finally, the responsibility of a PSC is not only to ensure safe and reliable power, but to do so at rates just and reasonable. To approve investment of huge sums of money into renewable energy with the knowledge aforehand that the actual utility of the invested capital to customers in 95 periods running from an hour up to 15 hours or more (7% of annual hours) is only 6%, seems imprudent. The additional cost of using batteries to make the utility of this investment behave more like 85-95%, like a thermal plant,  is ruinous.

Planning to Meet Demand

Figure 2. From PacifiCorp’s 2025 IRP.

Figure 2 shows how PacifiCorp intends to address growing demand though the 2025 IRP planning period. This plan encompasses the entirety of PACE and PacifiCorp west (PACW), not just PACE alone.

Consider 2030 which is right in the middle of the reliability shortfall the NERC assessment considers. Total of demand and obligations to deliver power in 2030, according to the 2025 IRP, is 13,000MW (without any plus or minus figure at all). The total of resources dedicated to meeting this amounts to about 27,000MW according to Figure 2. However, note what the mix of resources to cover this consists of. There is still 7,000MW of dispatchable coal and gas. Of the remaining 20,000MW of resource, though 2,000MW is speculative efficiency (that is load that never has to be supplied) plus response management; 18,000MW is wind+solar which I have argued is going to be at 10% capacity factor or less possibly 7% of the year; and, some additional generation is from batteries, which are not generation at all but rather represent an additional load to keep charged and might (probability unknown) be a true resource for some unspecified number of hours.

Just arithmetic suggests we are well below covering obligations and load. There is no reserve.

Conclusion

The looming problems with reliability are not just a matter of acquiring new resources too slowly, as the NERC report implies, but also a more daunting problem with procuring new resources that are difficult to quantify and expensive to make reliable. In my mind, I see lots of wishful thinking. A likelihood of blackouts well above 0.027%.

Notes:

1- As a measure of reliability this leaves much to be desired. 0.1 per year works out numerically equal to 1.0 days per ten years. However the costs of a day of unplanned outage once in ten years are likely to be very different than 2.4 hours once per year depending on location, customer and time of year. What a person would like to quantify is the cost of an outage. This was the topic of a recent episode of Energy Bad Boys, which was the inspiration for my essay, though I am writing here only about the likelihood of blackouts, not their costs.

2-Outage in the service area west of high plains west of Cheyenne, outages in the region of the disastrous fire in Superior and Louisville, Colorado in December 2022, and fires in northern California, etc.

3- Table 1 in the NERC report lists the factors.

4- The April 2025 outage in Spain, for example, occurred despite ample adequacy because of a lack of system mechanical inertia; that is, too much solar energy attached through inverters and not enough contributed by spinning turbines and generators which resist and damp electrical disturbances.

5- The most recent IRP from PacifiCorp has tempered this plan by planning to run most of its existing coal fleet out to the planning horizon in 2045 or so, but there is no mention of replacing thermal assets nearing their 50 year mark and aging out.

6 – Luckily someone did address this issue. The Federal Energy Regulatory Commission (FERC) stepped in, late in 2025, to demand that these coal plants remain operating.

7 – After September 2025 the Rock Creek I and II wind plants were being brought online in an unknown manner, making 2025 October through December aggregate wind energy deliveries possibly not comparable to these nine months.

8 – Known as a Convenience and Necessity hearing. 

9 – Demand response, shown in Figure 2 by year in PacifiCorp’s 2025 IRP, is roughly 1,000MW; a value roughly equal to total system load in the Wyoming portion of PACE. To play upon the quotation beginning this essay, I’d define it as “When the switch is flipped the lights don’t go on.”

The next Project Vault should protect America’s power grid

The Project Vault model to secure America’s electric power grid equipment makes strong strategic sense.

Project Vault, launched in February 2026, is a ~$12 billion public-private partnership (backed by a $10 billion EXIM loan plus ~$2 billion in private capital) that creates a demand-driven strategic reserve of critical minerals.

The Project Vault model to secure America’s electric power grid equipment makes strong strategic sense.

Project Vault, launched in February 2026, is a ~$12 billion public-private partnership (backed by a $10 billion EXIM loan plus ~$2 billion in private capital) that creates a demand-driven strategic reserve of critical minerals.

Manufacturers and OEMs commit upfront for access during disruptions, reducing reliance on volatile or adversarial supply chains (especially from China) without a traditional government-controlled stockpile like the Strategic Petroleum Reserve.

_____________________________________________________________________________________

From CFACT

By Dan Giamo

The United States is running short on the equipment that keeps its lights on. The components supporting our grid are difficult to procure, increasingly costly, and, for certain equipment, largely imported. That strain will only grow as electricity demand surges from AI data centers, electrification, and domestic manufacturing.

Luckily, a template to solve the problem already exists.

In February, the Trump administration announced Project Vault—a $12 billion initiative to build America’s first strategic reserve of critical minerals for civilian industry, backed by a $10 billion Export-Import Bank (EXIM) loan. Project Vault is still in its early stages, and important questions remain about its implementation. But the model it established—an EXIM-backed, demand-driven, public-private reserve that protects American competitiveness—has already demonstrated that the federal government can move quickly and at scale.

The next use for this model is obvious. America’s grid equipment shortage the reliability of the electric power system along with the economic growth and national security that depend on it. Call it Project SURGE—the Strategic U.S. Reserve for Grid Equipment.

The U.S. grid is under more pressure than at any point in modern history. Nearly one third of transmission infrastructure and one half of distribution infrastructure is near or past its intended lifespan. Electricity demand is skyrocketing, requiring new grid infrastructure. At the same time, extreme weather events are damaging existing infrastructure more frequently. Together, these factors have resulted in record grid equipment demand.

American supply chains have not kept pace. The equipment underpinning the electric system is increasingly expensive and hard to get. Prices for key components like transformers have quadrupled. Lead times have doubled, in part because of a yawning dependency on imports and uncertain supply chains. About 80% of large power transformers and 50% of distribution transformers are imported, and even domestically manufactured grid equipment relies heavily on imported inputs like laminations, stacked cores, and electrical steel.

These constraints have real consequences. Grid equipment shortages have delayed clean energy projects, limiting electricity supply while costs skyrocket, and caused data centers to sit empty waiting for power. Dwindling reserves of spare equipment leave utilities less able to restore service after disruptions, prolonging outages that already cost the economy over $120 billion a year.

The private sector and government have taken steps to address the shortage, but not at the necessary scale or speed. Manufacturers have committed nearly $2 billion to North American transformer manufacturing expansions since 2023. It will take years for all these facilities to come online, however, and many manufacturers are reliant on imported inputs. Industry operates vital stockpile programs—such as the Edison Electric Institute’s Spare Transformer Equipment Program and the Grid Assurance program—but these are generally limited to providing emergency backstops of specific components to large utilities and transmission owners. Electric cooperatives, public power utilities, and commercial and industrial customers are largely left out, as are domestic manufacturers who depend on imported inputs.

To support record-high demand, serve all consumers, and enable domestic manufacturing, a grid equipment reserve requires both a significant infusion of capital and coordination with a broad cross-section of industry. Building on the Project Vault model, EXIM can provide the capital to facilitate a large-scale grid equipment reserve designed around the actual needs of grid equipment consumers and manufacturers. Critically, SURGE can be executed within EXIM’s current authorities and requires no new money from Congress.

EXIM would provide a direct loan to an independent corporation—let’s say SURGE Co.—to purchase and store critical equipment and inputs needed for domestic equipment manufacturing. The government would not dictate what SURGE Co. stockpiles. Instead, it would bring together participants—utilities, power producers, data centers, other consumers, and domestic grid equipment manufacturers—to work with SURGE Co. to identify what goes into the reserve, mirroring Project Vault’s approach and avoiding duplication with existing private sector stockpiles. Like Vault, participants would pay a commitment fee for guaranteed access, which would fund loan repayment, storage, and other costs.

Participants would draw from the reserve in emergencies like supply disruptions, foreign export restrictions, natural disasters, or attacks. They could also draw for routine use, provided they replenish the reserve—like Vault. This inventory rotation smooths demand, prevents technological obsolescence, and keeps the reserve fresh.

The stable demand pull created by SURGE can also act as a tool to bolster U.S. domestic manufacturing. While statutory limitations may require SURGE Co. to initially purchase imported equipment, replenishments could be sourced from domestic manufacturers to boost production at home. And by stockpiling critical inputs, SURGE can give domestic manufacturers the supply chain certainty they need to invest in expansion.

Project Vault proved the federal government can move decisively to protect vulnerable supply chains. The grid equipment shortage is a version of the same problem. EXIM should work with industry and agencies like the Department of Energy to launch SURGE before the next crisis forces the issue.

This article originally appeared at Real Clear Energy

Utilities Efforts Would Undermine President Trump’s Ratepayer Protection Pledge

Electricity demand is rising for the first time in decades as data centers are built, manufacturing is reshored, and electrification increases. As White House National Energy Dominance Council officials explained at the Electric Power Supply Association’s annual summit, President Donald Trump and his administration are leading efforts to keep electricity prices affordable.

From Watts Up With That?

By Todd Snitchler

Electricity demand is rising for the first time in decades as data centers are built, manufacturing is reshored, and electrification increases. As White House National Energy Dominance Council officials explained at the Electric Power Supply Association’s annual summit, President Donald Trump and his administration are leading efforts to keep electricity prices affordable.

Most recently, President Trump and seven of the country’s largest tech companies signed the Ratepayer Protection Pledge to ensure that data centers pay for their own electricity costs and protect Americans from electricity price increases due to data center demand. Despite the administration’s efforts, some electric utilities in the mid-Atlantic are threatening to undermine the core principle of the pledge and shift the risk of building new generation onto captive customers.

In the 1990s, electricity markets across the country turned to competition, allowing independent power producers to compete in a marketplace that rewards the cheapest and most efficient power plants.

Some utilities, like Exelon, want to re-establish monopoly systems where they own and operate the power plants that generate electricity, the long-distance transmission lines, and the local distribution infrastructure. Under this model, utilities would build generation with guaranteed returns and shift construction risk, cost overruns, and performance failures directly onto ratepayers. Unlike a monopoly system, competitive markets put the risk of investment on the power producers and their investors, not the end users.

If power demand is rising so quickly, why aren’t utilities already building?

Utilities in competitive markets can still build generation today, they just have to do it competitively and without guaranteed returns. Consider National Grid Ventures’ recent announcement in New York. Despite being a major electric utility provider, its competitive affiliate, National Grid Ventures, is pursuing generation projects through competitive channels, accepting market risk rather than demanding ratepayer guarantees. New York and Governor Kathy Hochul have also been tackling affordability concerns by holding utilities accountable. Last month, Hochul moved to block Con Edison’s proposed rate increase and directed regulators to audit utility salaries across the state. Pennsylvania Governor Josh Shapiro also acknowledged that utilities lack public accountability, and transparency while making billions of dollars through guaranteed returns. 

Utilities’ own load forecasts show surging power demand, and their supporters argue that capacity markets are “loudly” signaling scarcity. If utilities are so confident in their own predictions, why are they not building generation already?

The answer is simple: utilities want the upside without the risk. They seek guaranteed cost recovery regardless of whether their projects succeed, whether costs spiral, or whether the forecasted demand materializes. Competitive power suppliers, by contrast, put their own capital on the line. If they build inefficiently or misjudge the market, investors—not ratepayers—absorb the losses, shielding customers from higher bills.

Utilities may also be exaggerating their own forecasts to increase profits. After Ohio introduced a new method of forecasting  data center demand, AEP Ohio’s “speculative data center queue” dropped from 30,000 MW to 5,642 MW of load when “substantial financial commitments” were required. Did 81% of projected demand evaporate overnight, or are utilities being less than diligent with their public projections? You be the judge.

Virginia is a clear counterexample

Exelon and other utilities have argued that returning to monopoly generation is needed to meet the growing demand, but that’s far from reality. If monopoly-owned generation was the clear answer to rising demand, one would expect that Virginia’s monopoly system has the power it needs to meet data center demand. Instead, Virginia is one of the top electricity importers in the country, relying heavily on power generated in states with competitive generation. 

Ensuring that the grid remains reliable is essential, and one of the ways that this is done is through capacity costs where power plants are paid to ensure they can deliver when electricity is needed. Virginia ratepayers face some of the highest capacity costs in the mid-Atlantic. In 2025 and 2026, capacity prices in Dominion’s service territory was 64% higher than the rest of the mid-Atlantic’s grid operator, PJM. When PJM’s capacity prices were near record lows, Appalachian Power’s capacity costs were more than 1,000% higher than the rest of the mid-Atlantic’s.

If monopoly generation is so much better at meeting demand efficiently and affordably, why would a state like Virginia have to import nearly a third of its power while paying significantly higher capacity prices?

Competition protects customers

Competitive markets have consistently delivered lower costs, faster innovation, and greater accountability than monopoly utility generation. Market participants respond to price signals, invest their own capital, and compete to serve customers efficiently.

Policymakers should resist calls to turn back the clock. Competition, not monopolies, will help the Trump administration protect customers from the costs of new energy infrastructure.

Todd Snitchler is President and CEO of the Electric Power Supply Association (EPSA).

This article was originally published by RealClearEnergy and made available via RealClearWire.

A Windy Day!

When it’s a windy day, guess what? We get a lot of wind power!

From NOT A LOT OF PEOPLE KNOW THAT

By Paul Homewood

When it’s a windy day, guess what? We get a lot of wind power!

Yesterday we got 60% of our power from wind:

National Grid: Live

It does not take a genius to work out that when Ed Miliband succeeds in tripling wind power capacity, there will be far too much wind power for the grid to handle.

I have analysed the half hourly generation data for the full winter just gone. It’s a fairly basic summary, but my model assumes a tripling of wind output, 4400 MW of fixed nuclear generation and existing demand profile.

It calculates that there will be 19 TWh of surplus wind power during those periods when wind and nuclear exceed demand. Obviously there will be other periods when wind and nuclear cannot supply all demand.

Whatever battery storage we have by 2030 will be far too tiny to make any difference, so most of that 19 TWh will have to be constrained. At a going rate of £100/MWh, that could cost £1.9 billion. And this is just for winter.

With much lower demand in summer and plenty of solar power as well, plenty more surplus electricity will have to be chucked away.

The problem is probably much worse still. Although I have not factored in higher demand, the increased proportion of offshore wind in the mix will increase wind generation above my projections.

There is also the issue of grid stability. I cannot see how the grid can operate stably with above 90% of generation coming from wind at times. Including some dispatchable power to stabilise the grid will automatically increase the projected surpluses.

Thirdly is the question of regional imbalances. Will the grid be able to cope with large amounts of wind power coming from Scotland and the North Sea? It is, of course, lack of transmission capacity which results in constraint payments to Scottish wind farms. OFGEM is busy spending tens of billions upgrading the grid, but whether even that will cope in future must be debatable.

Some of the surpluses are massive, as much as 32 MW on one occasion. Surpluses were above 20 MW on 16% of the three month period. The model also predicts that more than half of wind generation will have to be constrained for 10% of the time.

The practical difficulties faced by NESO in having to implement all of this, every half hour are mid boggling.

Just a glance at yesterday’s generation shows how huge the problem is. Demand was 35.9 GW. Of that, 21.5 GW came from wind and 3.4 GW from nuclear. Triple that wind capacity and you are looking at about 68 GW from wind and nuclear.

Half of that will have to be switched off on average, and more at times of low demand.

January 2026 Winter Storm Impacts on New York Grid

The January 2026 winter storm stressed electric systems across the country. It also offers electric resource planners an opportunity to examine the impacts of future increased use of renewable energy during high-load conditions. This article takes an initial look at the potential impact of such a weather event on the future New York electric system that relies on wind and solar.

From Watts Up With That?

By Roger Caiazza

The January 2026 winter storm stressed electric systems across the country. It also offers electric resource planners an opportunity to examine the impacts of future increased use of renewable energy during high-load conditions.  This article takes an initial look at the potential impact of such a weather event on the future New York electric system that relies on wind and solar.

There have been other articles about the January 23-27 winter storm impact on the electric grid.  Isaac Orr and Mitch Rolling described impacts to MISO, ISO-New England, ERCOT, and PJM.  They noted that there were no blackouts due to a lack of power generation possibly because “the storm didn’t bring on the high demand that previous winter storms brought in”.  David Middleton covered the storm impacts on ERCOT noting that fossil generation provided the power when renewables were unavailable. 

This article looks at the storm impacts on the New York grid and how a similar storm would affect the future grid of the state when the Climate Leadership & Community Protection Act (Climate Act) requirements for a 2040 zero-emissions grid kick in.

I relied on two sources of New York Independent System Operator (NYISO) data for this analysis.  New York fuel-mix load data are available at the NYISO Real-Time Dashboard.  The second source of data is the Operations Performance Metrics Monthly Report prepared by the NYISO Operating Committee.  I looked at data from January 22-31, 2026, to bound conditions before the storm and after.  Note that the cold weather went into February but the Metrics Report data for February is not available so I did not include February data in my evaluation.

New York Grid Impacts

The dashboard real-time fuel mix data includes links to current and historical five-minute generation (MW) for energy generated in New York State.  I processed that data to calculate hourly averages as described in a post on my blog.  Figure 1 graphs all the fuel mix hourly data. The relative average fuel mix energy provided over these ten days was nuclear 18%, hydro 14%, and fossil fuels 61% for a total of 93%. Six years after passing the net-zero transition legislation New York only got 7% of its energy over the last ten days of January from wind and solar.

Figure 1: Hourly NYISO Realtime Fuel Mix January 22 to January 31, 2026

I used the January  Operations Performance Metrics Monthly Report for this analysis.  This report includes a graph of net wind and solar performance.  It describes the wind; utility-scale solar, also known as Front of the Meter (FTM) solar; and the rooftop top solar also known as Behind the Meter (BTM) solar total daily production and capacity factors. 

Figure 2: Net Wind and Solar Performance Total Daily Production and Capacity Factors

Source: NYISO JanuaryOperations Performance Metrics Monthly Report

In New York the winter storm impacts started on the night of 24 January and total snow/sleet accumulation ranged from 8-13” near the coast and 12-17” across the interior.  As the precipitation ended a glaze of freezing rain occurred.  Following the storm there was a period of prolonged sub-freezing weather.  Figure 2 clearly shows the impact of snow on all solar production with no solar production on January 25.

Table 1 consists of three smaller tables.  On the left,  capacity factors derived from Figure 2 are listed for each day of the episode.  At the top, resource capacity (MW) from the Operations Performance Metrics Monthly Report are listed for solar and wind resources.  The main body of the table lists the calculated renewable daily energy (MWh) for each parameter and the renewable percentage of the total system energy that I calculated using the real-time fuel mix data.

Table 1: Capacity Factors Derived from Figure 5, Resource Capacity (MW) from Operations Performance Metrics Monthly Report, and Calculated Renewable Daily Energy (MWh)

The total renewable output in Table 2 is notable.  On average, wind resources counterbalance low winter solar resource availability.  However, during dark doldrums when the wind fails renewable resources plummet.  If such a period occurs after a significant snowstorm, then total renewable resources approach zero.

I have previously described the challenge of the gap between renewable energy production and peak loads and the potential solution.  The New York entities responsible for the electric system all agree that a new category of generating resources called Dispatchable Emissions-Free Resources (DEFR) is necessary to keep the lights on during periods of extended low wind and solar resource availability. The observed eight consecutive days where wind and solar resource availability was less than 6% of the potential capacity is a perfect example of the conditions that necessitate this new resource.

Electric System Projections

I used these results to evaluate projections made for the generating resources necessary to meet the 2040 100% zero emissions electric generation mandate. Table 2 lists the projected 2040 capacity (MW) for four scenarios that have been developed for the 2040 New York electric system.  I have included one scenario from the NYISO, the primary projection scenario from the Scoping Plan that outlined how the Climate Act 2040 mandate could be achieved, and two “Net Zero” scenarios from the draft New York Energy Plan developed last summer.  These scenarios represent four ways to achieve the 2040 mandate for zero emissions electric generation.

Table 2: Projected Electric Resource Capacity (MW) in 2040.

I detailed the process to estimate the impact of this storm on these resources if you are interested in more details.  I estimated the daily energy production for the projected generating resources in Table 2. Daily production equals the capacity in MW times the capacity factor times 24 hours in the day. Capacity factors were derived from the real-time fuel mix or taken from the Operations Performance Metrics Monthly Report data in Table 1. 

I estimated the 2040 daily energy production for each scenario by multiplying those factors by the Table 2 resource capacities.  Table 3 is an example of the daily production for the weather over this period.  Note that consistent with the zero-emissions mandate there are no fossil fuel (Gas and Fuel Oil) emissions.  Consistent with the NYISO projection for the winter peak, no imported hydro generation is included.  I calculated the battery storage energy production by multiplying the projected capacity times four hours (the current default discharge time).  This assumption is included every day but note that if the batteries need to be charged using renewables there are instances where there would be insufficient energy to recharge the batteries.  Finally, note that in this example, no DEFR production was assumed.

Table 3: Daily Production (MWh) for January 22, 2026

The goal was to compare the observed daily observed energy load against the projected energy projection for daily production in Table 3 to see if the resources provided enough energy to cover the observed generation load from the real-time fuel mix data during the conditions of the January 2026 storm.  Using the existing total load I found that weather like five days from Jan 22-31 created conditions in which resources excluding DEFR were unable to provide enough power generation to cover the January 2026 loads.  The NYISO 2025 Load & Capacity Data Report notes that New York electric system is projected to increase winter peaking load due to electrification, primarily from space heating and EVs.  When I accounted for that increase in load, none of the scenarios provided enough power from January 24-31 to prevent blackouts.

These results show that DEFR is necessary. When I included the DEFR resources operating at a capacity factor of 85% most scenarios provided enough generation to cover expected load  Because no DEFR technology has been identified the capacity factor value is arbitrary.  The one scenario exception to this was the “Net Zero B” option that never showed a surplus even with a 100% capacity factor.  My analysis found that at least 20GW of DEFR would be necessary to prevent a generation shortage if these conditions were to occur in 2040 for these capacity projections.

Dark Doldrum and DEFR

The most notable finding in Table 1 is the observation that there were eight consecutive days when the total New York wind and solar production was 6% or less than maximum possible energy production.  This is a perfect example of what the Germans call “Dunkelflaute”.  That term refers to dark doldrum periods when solar is reduced due to the length of day or clouds and there are light winds.  This event was exacerbated by the snowstorm that covered solar panels with enough snow to eliminate production (Figure 2).  Note that most rooftop solar in New York City is essentially flat so snow cover is a significant issue.  In this case the loss of solar was exacerbated by the snow depth, a crust of ice from a glaze of freezing rain that occurred at the end of the storm, and the subsequent period of prolonged sub-freezing weather. Perhaps we should amend the worst weather label to “snowy dark doldrums”.

These conditions are the fundamental driver of the need for DEFR.  It is disappointing that the clean energy advocates have continued to argue that the size of the DEFR gap has been overstated even after all the agencies responsible for electric system reliability argue otherwise.  These results should put those arguments to rest.

Conclusion

Large projected wind and solar capacities do no good when the sun doesn’t shine and the wind doesn’t blow.  During and following the January winter storm there were at least eight consecutive days when the New York total wind and solar production was less than 6% of the capacity available.  These are the conditions that require DEFR.  Without DEFR, intermittent, diffuse, and correlated electric generating resources are not viable.  Given that there is no commercially available DEFR technology available, proceeding under the assumption that one will magically appear is risky.

Roger Caiazza blogs on New York energy and environmental issues at Pragmatic Environmentalist of New York.  This represents his opinion and not the opinion of any of his previous employers or any other company with which he has been associated.

The AI energy crunch has a cure: End the “Endangerment Finding”

This summer, Americans are feeling the pinch as electric bills rise, and independent analysts predict staggering residential-rate increases of 30 to 60 percent by 2030 due to the growing demand from artificial-intelligence data centers. The time to address this situation is now.

A futuristic depiction of a data center with glowing blue accents, featuring a central cylindrical tower surrounded by server racks, set against a dark starry background.

From CFACT

By Melanie Collette

This summer, Americans are feeling the pinch as electric bills rise, and independent analysts predict staggering residential-rate increases of 30 to 60 percent by 2030 due to the growing demand from artificial-intelligence data centers. The time to address this situation is now.

A recent capacity auction reveals a dramatic increase in clearing prices—spiking more than tenfold in just two years—largely driven by data-center demand, which accounts for over 90 percent of the load growth in the grid system. Utilities are now faced with the monumental task of meeting this unprecedented demand, which will necessitate billions in new transmission and generation infrastructure. Unfortunately, these costs are likely to be passed on to consumers, culminating in higher electricity bills.

While AI isn’t inherently the problem, federal climate policies from 2009 create substantial obstacles. The EPA’s 2009 Endangerment Finding determined that greenhouse gases—including carbon dioxide—pose a threat to public health and welfare, and it supports EPA regulations that now impose strict CO₂ controls on long-standing coal units and most new baseload gas plants. This effectively delays the deployment of affordable, reliable energy sources capable of meeting the rising demand. Reversing this finding might be the most effective step policymakers can take to avoid an electricity-cost crisis related to the AI revolution.

The Hidden Surcharge: EPA’s Endangerment Finding

Why can’t utilities respond to surging demand by using cheaper energy sources? The 2009 Endangerment Finding provides the legal foundation for EPA regulations, including costly requirements like carbon-capture-and-storage (CCS) mandates and accelerated retirement dates for fossil-fuel power plants. Legal experts describe the Endangerment Finding as the “critical block” of federal climate regulations; if it were removed, the complex network of greenhouse-gas rules—especially those impacting power generation—could collapse.

In fact, the EPA estimates that repealing current standards would save the power sector $19 billion in regulatory costs over twenty years starting in 2026, or about $1.2 billion annually. Recently, the EPA proposed rescinding the Endangerment Finding, projecting it could save Americans over $54 billion each year by ending the chain of climate rules it initiated. Removing the CCS mandates alone could cut approximately $19 billion in costs over twenty years, which equals about $1.2 billion in savings beginning in 2026.

How The Finding Inflates Your Bill

EPA’s data suggests that mandatory CCS hardware and pipelines can inflate the capital costs of a combined-cycle gas plant by $800 to $1,600 per kilowatt. This additional expense translates to about 1.5 cents per kilowatt-hour in retail rates. Moreover, compliance deadlines embedded in the rule could force nearly 60 gigawatts of functional coal and older gas capacity offline before 2035, precisely when AI demand is expected to peak. This induced scarcity impacts household budgets well in advance of actual plant retirements.

Dispatchable Fuels Are Still America’s Workhorses

Natural gas remains a key player in the U.S. energy landscape, providing 43 percent of the country’s electricity, with combined-cycle units running at a 57 percent capacity factor last year. This demonstrates that natural gas plants are crucial for a grid under pressure.

Coal, while often criticized in climate discussions, still contributes 16 percent of electricity generation and serves as a reliable on-site fuel that keeps the lights on during extreme weather events. Federal policies, however, are accelerating the retirement of these assets faster than they can be replaced, which forces grid operators to rely on favorable weather conditions while coping with unprecedented demand from Big Tech.

Even within Silicon Valley, there’s acknowledgment of the looming crunch. Google has quietly agreed to pause non-essential AI workloads in Indiana and Tennessee during grid strain, recognizing that current infrastructure is insufficient for its ambitions. If even the most prosperous tech companies can’t guarantee continuous power for their AI initiatives, why should average families subsidize the necessary upgrades?

Repeal Is The Ratepayer’s Relief Valve

Repealing the Endangerment Finding stands as the relief valve that consumers desperately need. This process isn’t about deregulating AI; data centers will still pay market prices for electricity. What it will enable is allowing utilities to opt for the most efficient and cost-effective dispatchable technologies without incurring added CO₂ taxes. This change could considerably lessen electricity production costs, allowing utilities to work more effectively and pass those savings on to consumers.

EPA’s repeal proposal will face legal challenges and political headwinds, but lawmakers do not have to sit on the sidelines. They can codify the repeal, bar the agency from re-imposing CCS mandates through backdoor rulemakings and restore a simple principle: energy policy should serve the people who pay the bills, not the industries that create them.

America can power an AI revolution and keep kitchen-table costs under control. It starts by pulling one regulatory brick—the Endangerment Finding—so the rest of the wall comes down and affordable electrons can flow again.

This article originally appeared at The Daily Caller