Mike Howells's Blog

Tag: electricity

The Night MISO Had 204 Megawatts Left
It started with a number I did not expect to see in September. On Wednesday, September 2, 2026, MISO’s demand peaked at 123,718 MW. That is the figure from MISO’s real-time supply and demand feed, which publishes on a fifteen-minute grid, recorded at 5:00 PM ET. On the hourly zonal accounting it comes to 123,145.9 MW in the hour ending 6:00 PM ET. Both numbers are correct and they measure slightly different things, which is a theme of this post. MISO’s own post-event review gives a third, 122.9 GW, and calls it an all-time September peak, without saying which measure it used.

On the hourly series it was the third-highest peak of the summer, behind only June 29 and June 30, and the highest single day since June 30. That evening MISO declared an emergency, and the grid came within 204 MW of running out of committed supply.

I want to explain why that happened, because the interesting part is not that the grid got stressed on a hot day. It is that it took three things going wrong at once. Two of them I can see in my own archive, and I can show with the rest of the summer’s data that neither would have been enough on its own. The third I could not see at all until MISO published its own review of the evening on September 25 and walked its reliability stakeholders through it on September 29.

The vocabulary, quickly

MISO is the Midcontinent Independent System Operator, the organization that runs the wholesale electricity market and balances supply against demand across fifteen states and one Canadian province, including most of eastern Missouri, which is Ameren’s territory.

Committed capacity is the generation MISO has actually instructed to be running or ready to run in a given interval. Margin is committed capacity minus demand: the cushion. When margin goes to zero, something has to give.

EEA stands for Energy Emergency Alert. It is a term from NERC, the North American Electric Reliability Corporation, which sets and enforces reliability standards for the power grid across the United States, Canada and part of Mexico. It comes in three levels, which MISO declares as steps of a Maximum Generation Event. Step 1 means MISO is using generation it normally holds back. Step 2 opens up emergency actions, which can include buying emergency energy from neighbors and calling on customers who are contracted to cut demand. Step 3 is controlled load shedding, which is to say deliberate outages. September 2 reached Step 2.

MTLF is the Mid-Term Load Forecast, MISO’s own prediction of how much electricity the system will need. There are two forecast products carrying that name and telling them apart matters later.

MISO labels its timestamps EST all year. In September that runs one hour behind Eastern Daylight Time, so a MISO time stamped 18:44 is 7:44 PM ET. All times in this post are Eastern.

What happened, in order

The heat had been building since the weekend. MISO put its whole footprint under a Hot Weather Alert, Conservative Operations and a Capacity Advisory at 7:00 AM ET on Monday, August 31. On September 2 it posted a Hot Weather Alert notice at 2:11 PM ET and updated its Conservative Operations Declaration, a routine posture change, at 4:59 PM ET. None of that is unusual for a September heat wave. The system carried a comfortable cushion through the afternoon.

Demand peaked at 5:00 PM ET with 6,574 MW of margin still in hand. That is not a lot on a 123 GW system, but it is not an emergency either.

Committed capacity then kept climbing for more than an hour after demand had turned over, reaching 133,144 MW at 6:15 PM ET. That is why the cushion was wider at 6:30 PM ET than it had been at the peak. What happened next is that committed capacity fell 13,787 MW over the following two hours while demand fell only 3,805 MW.
- 6:30 PM ET: margin 10,147 MW
- 7:00 PM ET: margin 8,488 MW
- 7:30 PM ET: margin 6,476 MW
- 7:40 PM ET: MISO is importing 11,400 MW from its neighbors
- 7:44 PM ET: MISO declares a Maximum Generation Event Step 1 (EEA 1)
- 8:00 PM ET: margin 2,456 MW
- 8:05 PM ET: imports are down to 6,900 MW
- 8:07 PM ET: MISO deploys about 1,800 MW of its contingency reserves, the generation it holds ready to cover a sudden loss
- 8:11 PM ET: MISO escalates to Step 2 (EEA 2)
- 8:15 PM ET: margin 204 MW, the low point of the day, with demand at 119,153 MW
- 9:30 PM ET: MISO steps back down to Step 1
- 9:44 PM ET: the event is terminated
- 11:00 PM ET: by now every import curtailment has ended
Figure 1 shows the whole afternoon and evening. What you are looking at is the teal line, committed capacity, falling faster than the dark gray line, demand. Demand was already coming down from its peak. Committed capacity came down faster.

Figure 1. Demand against committed capacity on September 2. The shaded band marks the import cut; the low point was 204 MW at 8:15 PM ET.

MISO’s review charts a different cushion. Its online reserve margin goes below zero at about 8:00 PM ET on MISO’s chart and stays there for about three quarters of an hour. The slide labels that chart as the North and Central regions, but MISO said at the September 29 meeting that the label is wrong and the line covers the whole system. My 204 MW is committed capacity minus demand across the whole footprint, read from the public feed. So the two cover the same territory, and the difference between them is what they measure. MISO has not defined its measure, but one named for reserves will not read the same as mine. Both are correct. On either one, the evening ran out of room.

The marginal energy cost, which is roughly the price of the next megawatt, touched $10,000 at 8:05 PM ET, the same minute MISO’s imports hit their low. That is MISO’s value of lost load, or VOLL, the price it puts on electricity that cannot be delivered, and it doubles as the ceiling on market prices. The Federal Energy Regulatory Commission, or FERC, which regulates wholesale electricity markets, approved raising it from $3,500 to $10,000 effective September 30, 2025, so the summer of 2026 is the first with a $10,000 ceiling. MISO’s review says the intervals where its fleet could not ramp fast enough were priced at exactly that ceiling. The daily mean was $578.

MISO’s own declaration named four causes: above normal temperatures, higher than forecasted load, loss of import interchange schedules, and transfer capabilities. MISO’s post-event review, posted on September 25 and presented on September 29, leads with the third and fourth. I take them in the order I found them: load, then forecast, then imports.

The first condition: a near-record load

June 1 through September 6 gives 98 days of peaks. On the hourly zonal series, September 2 sits third, 1,927 MW below June 30 and 35 MW below June 29. On its own that is a hard day, not an emergency. June 30 carried a higher peak and June 29 carried a peak within 35 MW, and the summer absorbed both.

There is a second thing worth noticing about the date. September 2 was a Wednesday. Across the season the average weekday peak was 108,327 MW and the average weekend peak was 101,622 MW, a gap of 6,705 MW. The workday itself is worth about six and a half gigawatts. The heat wave broke over the following holiday weekend, with 107,774 MW on Saturday and 101,105 MW on Sunday, and the emergency did not repeat.

Figure 2. Daily peak demand, June 1 to September 6, 2026, weekdays in teal and weekend days in orange.

The second condition: the forecast was low

Every day, MISO publishes a day-ahead forecast: a full 24-hour load prediction produced the day before, which then stays fixed. For September 2 that forecast was built on September 1. At the hour when demand actually peaked, it was 3,590.9 MW below what happened.

That is the second-largest under-forecast of the summer out of 98 days. Only July 6 was worse, at 4,539.2 MW.

Figure 3. Hourly load against MISO’s day-ahead forecast on September 2, with each hour’s miss below. Orange bars mark misses above 3,500 MW.

The miss was not confined to the peak hour. It opened up around the hour ending noon ET and stayed open through the last hour of the day, running above 3,500 MW for four consecutive hours across the late afternoon and evening. The largest single hour was the hour ending 7:00 PM ET at 3,928.6 MW.

It was also not spread evenly across the footprint. MISO divides its territory into Local Resource Zones, or LRZs, and in the hour ending 8:00 PM ET the forecast miss broke down like this:
- LRZ1 (Minnesota, the Dakotas, western Wisconsin): 1,526.0 MW
- LRZ6 (Indiana): 830.4 MW
- LRZ3_5 (Iowa, Missouri): 422.3 MW
- LRZ2_7 (Wisconsin, Michigan): 377.7 MW
- LRZ4 (central and southern Illinois): 354.2 MW
- LRZ8_9_10 (Arkansas, Louisiana, Mississippi, Texas): 316.6 MW
LRZ1 accounted for 40 percent of the miss while carrying 13.5 percent of the load. One zone in the north was substantially responsible for a shortfall that turned into a system-wide emergency.

Why neither of those alone explains it

This is the part I find most useful.

July 6 carried a larger day-ahead miss than September 2, 4,539.2 MW against 3,590.9 MW. It peaked at 111,776.2 MW, which is 11,369.7 MW below September 2. A big forecast error on a moderate day is absorbed by the supply that is already committed.

June 30 carried a higher peak than September 2, 125,073.4 MW against 123,145.9 MW. Its day-ahead forecast ran 1,782.6 MW above actual. A near-record day that MISO saw coming is a day MISO has already committed generation for.

Figure 4 puts all 98 days on one chart, peak against forecast miss. Above 120 GW and missed low by more than 3 GW, there is exactly one day in the corner.

Figure 4. Every day of the summer, peak demand against the day-ahead forecast miss. September 2 is alone in the corner.

That is the whole argument in one picture. September 2 was not the biggest day and it was not the worst forecast. It was the only day that was close to both at once.

That set the stage. It did not pull the trigger.

The third condition: the imports went away

At 7:40 PM ET, MISO was importing 11,400 MW from its neighbors. Twenty-five minutes later it was importing 6,900 MW.

The reason is a procedure called transmission loading relief, or TLR. When a transmission line or transformer is carrying more than it safely can, the coordinator responsible for it can call a TLR, and the scheduling system cuts, or curtails, the scheduled power deliveries whose flow crosses that element. The TLR is the order; the curtailments are the cuts it produces. The procedure does not ask who needs the power. A delivery into MISO gets cut if its path loads the constrained element, even while MISO is short. Level 3, the level called on September 2, cuts the lower-priority schedules first.

According to MISO’s review, three Level 3 TLRs were called that evening:
- PJM, the grid operator to the east, called one on a 500 kV line in Pennsylvania
- IESO, Ontario’s grid operator, called one on the Ontario to Michigan interface
- MISO called one on a transformer in Missouri
Figure 5 shows where they were.

Figure 5. Where the three TLRs were called on September 2.

They did not arrive together. The review was presented on September 29 by the Manager of Shift Managers in MISO’s System Operations group, and he described the pattern as one TLR cutting a couple of thousand megawatts on fifteen minutes’ notice, then another arriving ten minutes later to cut a couple of thousand more. PJM’s and IESO’s did most of the damage. MISO’s own came about ten minutes after those and cut a few hundred megawatts. Together the three curtailed 3,900 MW of imports. He also confirmed to me by email that ordinary schedule changes account for the other 600 MW of the drop. MISO’s own TLR was on a transformer in my home state. MISO does not say which one, and I have not been able to find out.

The two big ones were probably linked. He was careful not to speak for PJM or IESO, but his reading was that the Pennsylvania line was congested, made worse by outages in the area, and that when PJM curtailed schedules across it, some of what it cut were IESO’s. IESO then called its own TLR to free up supply for itself. One probably led to the other. The outages matter here. September is when grid operators take equipment out for maintenance, because demand is normally falling, and MISO’s review lists the start of fall outage season among the conditions going into September 2. At the meeting MISO’s staff added that transmission construction was under way both inside MISO and among its neighbors.

MISO’s review also mentions a second supply problem: solar output fell off somewhat faster in the evening than MISO had forecast. At the meeting he played it down, calling it a typical evening ramp and saying the TLRs were what mattered most. The deck gives no megawatts for it, so I cannot size it, and I am not going to lean on it.

The timing lines up with figure 1, where the shaded band marks the twenty-five minutes of the import cut. Margin went from 6,476 MW at 7:30 PM ET to 204 MW at 8:15 PM ET, the same forty-five minutes that contain the import drop. My archive’s committed capacity series does not break out imports, so I cannot say how much of the 13,787 MW it lost over the evening was the curtailed schedules. MISO deployed its contingency reserves two minutes after the import low. On MISO’s chart, the frequency of the Eastern Interconnection, the single synchronized grid covering most of the United States and Canada east of the Rockies, dipped and recovered within about a quarter of an hour. Asked about that at the meeting, MISO said the dip was its own: its generators could not ramp up fast enough to replace roughly 4,000 MW of lost imports in a few minutes, and the whole interconnection felt it.

Frequency is the grid’s heartbeat. Every generator in the Eastern Interconnection spins in step at 60 cycles per second, or 60 hertz (Hz), and when demand outruns supply they all slow slightly. On September 2 the frequency fell to about 59.955 Hz by 8:00 PM ET, held there through the import low, and was back above 60 Hz by about 8:12 PM ET. It then ran a little high through the end of MISO’s chart at 8:30 PM ET as the response overshot, which MISO said is typical once reserves are deployed. Figure 6 traces it from MISO’s own chart.

Figure 6. Eastern Interconnection frequency on September 2, traced from MISO’s chart.

MISO describes a TLR curtailment this large, on this little notice, during peak hours, as rare. At the September 29 meeting, one longtime stakeholder said he could not remember TLRs causing a problem like this in decades, and MISO’s presenter called it an unusual event. Its review lists what it is looking at: closer coordination with PJM and IESO before large curtailments, staggering curtailments across an hour where the issuing coordinator allows it, and alternatives to TLRs for its own internal constraints, so that relieving one transformer does not cut supply in the middle of a capacity emergency. At the meeting MISO added one more. It is working with OATI, the company that runs the Interchange Distribution Calculator, the Eastern Interconnection’s tool for working out which schedules a TLR cuts, on whether a problem in that tool played a part. MISO had only just received that information and would not characterize it. It expects to bring a fuller account back to the subcommittee at a later meeting.

There is one more thing a TLR explains. It is a same-hour decision. It does not appear in an hours-ahead supply forecast, because it has not happened yet.

What the forward view showed, and what it did not

I keep an archive of MISO’s published forward view, which is refreshed every few minutes and contains, for each hour ahead, the forecast demand, the capacity MISO has committed, and the capacity MISO reports as available. From that I can replay exactly what the published picture looked like at any moment of the day.

At 3:45 PM ET, roughly four hours before the emergency, the view of the hour ending 8:00 PM ET read: forecast demand 119,561 MW, committed capacity 125,851 MW, available capacity 128,237 MW. Forward margin 6,290 MW. No hour from 5:00 PM ET to 11:00 PM ET showed a forward margin below 6,290 MW.

I also track what I call the uncommitted stack: available capacity minus committed capacity, which is the supply MISO says it has but has not yet instructed to run. On July 26 it fell to 1,245 MW for the evening hour by 6:55 PM ET, and the price hit $1,203 at 8:50 PM ET. On September 2 it never came close to that. Reading the evening hour at one hour or more of lead time, which is the window I report, it ran between 2,048 MW and 2,580 MW all day, and it was higher than on several calm days. Inside the last hour it falls to 745 MW, but by then the margin collapse is already on the screen and the stack is telling you nothing you did not know.

Figure 7. MISO’s uncommitted stack for the hour ending 8:00 PM ET, through September 2.

It is natural to expect the uncommitted stack to work as an early warning. It does not. In a five-day backtest, the stack on September 2 was healthier than on days when nothing happened, so it would have pointed the wrong way. I am leaving the chart in because a signal that fails is worth showing.

So on the supply side, MISO’s published forward view carried no warning by any construction I have tried.

The one signal that was there

The demand side is different, and this is where the two forecast products matter.

There are two things called MTLF, MISO’s Mid-Term Load Forecast. The Data Exchange returns the day-ahead run, initialized the day before and then fixed. The retiring market report file carried the last intraday revision. For the hour ending 8:00 PM ET on September 2:
- Day-ahead MTLF: 116,860 MW
- Intraday-revised MTLF, from the market report file: 117,016 MW
- Actual: 120,687 MW
Both forecasts were low. But watch what the intraday view did through the day.

Figure 8. MISO’s forecast for the hour ending 8:00 PM ET, as it changed through September 2.

Through the afternoon MISO’s own forward view of that evening hour climbed steadily as the day got hotter, from 116,869 MW in the morning up to 120,116 MW by 5:15 PM ET. At that point it was within 571 MW of what the hour actually delivered. MISO had it very nearly right.

Five minutes later, at 5:20 PM ET, that forecast was revised down by 3,587 MW to 116,529 MW.

No other hour moved. The hours ending 6, 7, 9, 10 and 11 PM and midnight ET all drifted by a few tens of megawatts across the same step, which is normal. Only the hour that was about to break the system was revised, and it was revised in the wrong direction, from 571 MW away from the eventual actual to 4,158 MW away.

That was 2 hours and 24 minutes before the EEA 1 declaration.

I do not know why. A single-hour revision of that size, moving against the trend of every neighboring hour, is either a correction MISO had a specific reason for or a model artifact. What I can say is that the corrected view partly recovered afterwards, reaching 117,014 MW by 6:00 PM ET and climbing back through the 7:00 PM ET hour, and that MISO’s own declaration two hours later named “higher than forecasted load” as a cause of the emergency.

Two notes on the numbers in this section, since both changed what I thought I was looking at. The 117,016 MW above is the market report file’s final revision for that hour. The 117,014 MW is the forward view at the 6:00 PM ET vantage point. They are two megawatts apart because they are two different products, not because either is wrong. And if you compare only the top-of-hour snapshots at 5:00 and 6:00 PM ET, the revision reads as 2,961 MW and appears to happen at 6:00 PM ET. Sampling the feed every five minutes shows it as a single 3,587 MW step at 5:20 PM ET followed by a partial recovery. Coarse sampling moved both the size and the timing.

The morning after

On September 3, MISO’s day-ahead forecast ran 3,897.5 MW above actual. That is the largest over-forecast of September and the fourth largest of the summer, behind July 4, August 12 and August 6.

I am not going to claim that is a deliberate overcorrection, because I cannot see inside the model and a single day proves nothing. It is worth writing down and watching.

What I take from it

Grid emergencies get reported as though there is one cause. There usually is not.

September 2 was a workday in a heat wave, which put load near the top of the season. The day-ahead forecast was the second worst of the summer, concentrated in one northern zone. Neither fact would have made the news alone, and I can point at July 6 and June 30 to show it. Together they left MISO committing generation for a system 3.6 GW smaller than the one it actually had. Then, in the twenty-five minutes around the first declaration, a congested line in Pennsylvania set off a chain of curtailments through PJM and Ontario, a smaller one of MISO’s own in Missouri followed, and 3,900 MW of imports were cut. The cushion ran out at 8:15 PM ET with 204 MW to spare.

None of the forward supply numbers warned of trouble, and with MISO’s review in hand, that makes sense. A large share of the supply lost that evening came from import cuts ordered with fifteen minutes’ notice, and no forecast made hours earlier could have included them. The demand numbers were different. At 5:15 PM ET, MISO’s own forecast for the hour ending 8:00 PM ET was 120,116 MW, within 571 MW of what actually arrived. Five minutes later, MISO cut that forecast by 3,587 MW, even though demand for that hour came in higher. A big cut to a forecast that was nearly right is visible in the data hours ahead. What I do not know yet is whether it means anything. If cuts that large happen often on days when nothing goes wrong, they are noise; if they show up mainly before trouble, they are a warning. One day cannot settle that, so that is the next question I want to answer.

A few notes on the data. The peak figures here are demand as reported. MISO simplified its Maximum Generation Event steps on June 1, 2026, folding a five-step structure with letter sub-steps into three steps aligned to the NERC alert levels, which is why the September 2 notifications read “Step 1” and “Step 2” with no letter where older declarations read “Step 1b” and “Step 2a.”

Under the current structure, calling on load modifying resources, meaning customers under contract to cut demand during a declared emergency, is one of a broad set of actions available inside Step 2 rather than a step of its own, and the public notifications do not say whether MISO used it. At the September 29 meeting, one member utility asked MISO to say more, during any future Step 2, about which actions it is actually taking. The same MISO manager confirmed that MISO did not schedule or implement load modifying resources as part of Step 2 on September 2. Whether any companies cut load on their own, without instructions from MISO, is not known, so I have not adjusted for curtailment in either direction.

MISO has announced that it will stop posting its Pricing and Load, Generation, and Interchange market reports in favor of the Data Exchange API, with already-posted files remaining until they expire. The date has moved twice: from December 12, 2025, to September 30, 2026, and then, according to MISO’s liaison report for its October 1, 2026, Market Subcommittee meeting, to March 25, 2027. I tested the replacement: it serves the day-ahead run and only the day-ahead run, so the intraday-revised figure quoted above will have no successor once the reports stop. The fifteen-minute forward view this post leans on comes from a different feed and is unaffected. Losing the intraday figure is a problem for another post.

I now post the daily numbers on X at @MISOGridWatch: the day’s peak demand, the margin and any emergency declarations, without the commentary.

Figures 1 through 4, 7 and 8 are rendered from my archived data. Figure 5 uses MISO’s review and Natural Earth boundaries, and figure 6 is traced from MISO’s own chart. All times are Eastern (ET), converted from MISO’s year-round EST timestamps.
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October 1, 2026
Why Every Power Supply in Your House Says “100–240V” (A Story About Japan)

I was getting ready for an upcoming trip to Switzerland and Italy, and I picked up the power brick for my laptop to check whether it would handle European voltage. The label said INPUT: 100–240V, which is exactly what I wanted to see. I can plug it in over there with just a plug adapter, no transformer needed.

But then I stopped and looked at that number again. 100 volts. Who runs on 100 volts? The U.S. runs on 110 to 120. Europe runs on 220 to 240. Most of the world is in one of those two camps. So why does basically every power brick I own, including phone chargers, laptop supplies, and electric toothbrushes, quote a range that starts at 100 instead of 110?

I went down the rabbit hole. The answer turned out to be one of the best pieces of accidental history I’ve ever stumbled into. So this week, we’re taking a break from my electric bill to talk about Japan.

The country that runs on 100 volts

Japan is the only major country in the world where household power is nominally 100 volts. Not 110, not 120, not 220. One hundred. Everyone else clusters around either the North American standard (110 to 120V) or the European/Australian standard (220 to 240V). Japan sits by itself.

And the reason is essentially two separate stories of inertia that converged into one strange national outcome. Two competing electric companies, in two different Japanese cities, bought their first generators from two different countries within about a year of each other in the mid-1890s. Nobody coordinated. Nobody planned. And once the decisions were made, it was too expensive to undo any of it.

But it gets weirder. Japan didn’t just end up with a unique voltage. It ended up with two incompatible electrical grids inside the same country, and the country still can’t fully share power between them today. That’s the part that really got me.

Meiji-era Japan was buying everything from everyone

To understand how this happened, you have to know what Japan looked like in the 1890s. The Meiji Restoration had ended a couple of decades earlier, and Japan was in the middle of an extraordinary national project to modernize. They had spent more than 200 years deliberately sealed off from most of the outside world, and now they were trying to catch up to the industrial West in a single generation. The strategy was straightforward: figure out who was best at each thing, buy their stuff, and learn from it. Naval architecture from the British. Army organization from the Prussians, then the French. Medicine from the Germans. Universities patterned on the American and European models.

Electricity was brand new. Edison’s first commercial power station in New York had opened in 1882. By the 1890s the technology was spreading fast, but there were no international standards. Different manufacturers in different countries had settled on different frequencies, the rate at which alternating current cycles back and forth, and there was no reason to think any of it mattered yet.

So when Japanese cities started electrifying, they did what Meiji Japan did with everything else: they shopped around.

1895 and 1896: two cities, two suppliers

In 1895, the Tokyo Electric Light Company bought its first alternating-current generators from AEG, a German firm that was one of the giants of European electrical engineering at the time. Those generators ran at 50 hertz, the German standard.

The next year, in 1896, the Osaka Electric Light Company bought its first generators from General Electric in the United States. Those ran at 60 hertz, the American standard.

Tokyo and Osaka are about 500 kilometers apart. In 1896, the grids were tiny, local, and isolated. Each one served the immediate area around a single city. The idea that they would someday need to talk to each other, that there might eventually be a single national grid stretching the length of Japan, was not on anyone’s mind. Why would it be? Electric service barely reached the edge of town.

A quick note on the voltage

You might be wondering: if the German and American generators ran at different frequencies, did they also force the voltage difference? They didn’t. Voltage and frequency are independent properties of a generator, set by different design choices. The voltage story is separate, and it’s the less dramatic one.

Early electrical equipment everywhere in the world ran at relatively low voltages in the 1890s, typically around 100 to 110 volts, because that’s what Edison-era bulbs and motors were built for. The U.S. started there too. The difference is what happened next. Over the following century, the United States gradually crept up to 120 volts to reduce line losses as appliances grew more demanding. Europe pushed all the way up to 220 to 240. Japan didn’t. They started at 100 and stayed at 100.

The mid-20th-century Japanese government actually did consider raising the voltage closer to European levels. They decided not to. By that point too many homes, factories, transformers, motors, and appliances had already standardized on 100 volts. Replacing all of it nationwide was going to cost more than living with it. So they didn’t.

That’s why Japan is stuck at 100 volts. Not because of a 19th-century accident, but because of a 20th-century cost-benefit decision that said the accident wasn’t worth fixing.

The frequency split, on the other hand, is the 19th-century accident. And it gets worse over time, not better.

The grids grew until they ran into each other

Over the next few decades, electricity spread across Japan. Tokyo’s 50-hertz grid expanded eastward and northward, eventually covering Hokkaido, Tohoku, the Kanto region, and parts of central Honshu. Osaka’s 60-hertz grid spread west and south, covering Kansai, Chugoku, Shikoku, and Kyushu. By the 1920s, surveys showed that around 83 percent of the Tokyo region was on 50 Hz and 87 percent of the Osaka-Nagoya region was on 60 Hz. The two systems were no longer isolated city grids. They were regional power networks. And they were heading toward each other.

The boundary they eventually settled on runs roughly along the Fujigawa River in Shizuoka Prefecture, up through Itoigawa City in Niigata Prefecture. Cross that line and the frequency changes. Everything east of it is 50 Hz. Everything west is 60 Hz. A microwave you bought in Tokyo might not work properly in Osaka, and vice versa, depending on the model.

Japan’s electrical frequency split. Eastern Japan runs at 50 Hz; western Japan runs at 60 Hz. The red line marks the boundary. Map via Wikimedia Commons.

Japan is, as far as I can tell, the only country on the planet running two incompatible electrical frequencies inside its own borders. And just like with the voltage, the mid-20th-century government considered unifying the country on a single frequency and decided the cost was prohibitive. So they didn’t.

The bill from 1896 came due in 2011

For most of the 20th century, the frequency split was an inconvenience but not a crisis. The two halves of the country were connected by a small number of frequency converter stations, facilities that take AC power off one grid, convert it to DC, and then synthesize a new AC waveform at the other frequency to push it onto the other grid. There are only a handful of these stations. Their combined capacity is limited. For decades, that was good enough.

Then in March 2011, the Great East Japan Earthquake hit. The Fukushima Daiichi nuclear plant was destroyed. TEPCO, Tokyo’s utility, lost a huge chunk of its generating capacity overnight, right at the moment Tokyo needed electricity most. And the painful realization sank in: more than half of Japan’s total generating capacity was sitting on the other side of the frequency line, in the west, and there was no way to move enough of it east.

The converter stations could push around 1.2 gigawatts across the boundary in total. TEPCO needed multiples of that. The west had power to spare. The east couldn’t get to it. Tokyo went through rolling blackouts.

That moment, more than any other, made it clear that a decision two electric companies made in 1895 and 1896, without coordinating, without thinking about national infrastructure, without any reason to imagine the grids would ever meet, was still constraining Japan more than 115 years later.

They’re still paying for it

The response to 2011 included a national push to build more converter capacity, and that work is still happening right now. In October 2023, Mitsubishi Electric was awarded a contract to supply a new 300-megawatt HVDC frequency converter at the Shin-Sakuma station in Hamamatsu, Shizuoka. The system is expected to enter service by the end of March 2028. That’s a 130-year-old decision still generating engineering contracts and capital expenditures in the 2020s.

I find that detail genuinely hard to absorb. Two procurement decisions made by separate companies in separate cities in 1895 and 1896, neither one of which had any idea the other was happening, neither one of which was thinking past the next few city blocks, are still costing Japan money and constraining Japan’s grid in 2026. The decisions weren’t reversed. They couldn’t be reversed. The country just adapted around them, and is still adapting.

What this has to do with your phone charger

Here’s the punchline. Modern electronics use switching power supplies, the little bricks at the end of every cable, that can accept a wide range of input voltages. That’s why they work in different countries. But the specific range on the label, 100 to 240V, was not chosen arbitrarily.

The top end, 240V, is there to cover Europe, Australia, the UK, and most of Asia. The bottom end, 100V, is there for one country. Japan. If Japan ran on 110V like the United States, the standard label on every charger in the world would say 110 to 240V instead, and manufacturers would have a slightly easier time of it. But they don’t. They have to cover Tokyo and Osaka too. So the universal input range starts at 100.

Every Apple charger. Every Dell laptop brick (including the one I was looking at). Your electric toothbrush. Your phone. Pick one up and look at the back. It almost certainly says 100–240V, and that lower bound exists because Japan chose, in the mid-20th century, that fixing the accidental decisions of the 1890s would cost more than living with them.

The whole world’s electronics carry a small fingerprint of 19th-century Meiji-era Japan, baked into the label on every power brick. Most of us have looked at that number a thousand times and never wondered why it was 100 instead of 110.

I picked up my laptop’s power brick to figure out I could take it to Europe. Turns out I also learned why my microwave wouldn’t work in Tokyo.

Next week: a story I’ve been wanting to tell for a while about a small black box on my home network called a Pi-hole, and what it’s done to my view of how the internet actually works.
Fediverse Reactions
June 28, 2026
Why Your Electric Bill Is About to Get Weirder

Part 4 of a series on what I learned by accident when I started paying attention to my electricity bill.

I started this series four weeks ago with a story about my dishwasher. About switching to Ameren Missouri’s Ultimate Saver rate plan, about figuring out that 10 PM was a meaningful number, about the small habit shift that came out of it.

Then I spent three posts pulling at the thread that started with my dishwasher. I wrote about how a continental-scale power grid actually works and how it almost broke in 2003. I wrote about how a new category of customer is now creating conditions that look uncomfortably similar to 2003, on purpose, at scale, with the explicit acknowledgment of the regulators that they cannot keep up. Along the way I told you about megawatts and gigawatts and the May 2026 NERC alert, about hyperscalers building their own private power generation outside the regulated planning process, about an honor system that depends on data center operators picking up the phone when grid operators call.

I want to bring all of this back to where it started, which is my electric bill. And yours. Because the buildout I described in Post 3 is not happening in some abstract national context that doesn’t affect ordinary residential customers. It is happening, and it is going to show up on your bill, and the question worth asking is what that looks like and what, if anything, you can do about it.

That’s what this post is about.

Capacity prices, and why they matter to you

The first thing worth understanding is that your electric bill is not just paying for the electricity you used last month. It is also paying for the capacity that has to exist in order to serve you when you need it.

This works like an insurance pool. The utility, and the regional grid operator, have to maintain enough generation and transmission capacity to meet the worst-case demand on the worst possible day, plus a reserve margin in case some of that capacity fails. That capacity costs money to maintain whether you use it or not. The cost of maintaining it gets recovered from customers, spread across everyone, embedded in the rates you pay every month.

The wholesale market that determines how much that capacity costs is called the capacity market, and in MISO, the regional grid operator for Missouri and 14 other states, the capacity market runs annual auctions to determine prices. For most of the past decade, those prices were stable, low, and not particularly newsworthy. As recently as the 2024 to 2025 planning year, MISO’s capacity cleared the auction at about thirty dollars per megawatt-day.

In the auction for the 2025 to 2026 planning year, capacity prices jumped to six hundred sixty-six dollars per megawatt-day. That is a twenty-two-fold increase in a single year. The capacity market is, in effect, screaming that the system is running out of margin.

There is no version of that increase that does not, eventually, find its way into retail electricity rates. The math is unavoidable. Utilities buy capacity through these markets. They pay the cleared price. They recover that cost from customers. A twenty-two-fold increase in wholesale capacity prices does not stay wholesale.

What it means in practice is that even if you used exactly the same amount of electricity this year as you did last year, even if your behavior did not change at all, the underlying cost of keeping the grid available to serve you has gone up dramatically. Some of that cost is already showing up in rate cases being filed by utilities right now. Most of it has not arrived yet. It will.

Who pays when the biggest customers leave

There is a second, more subtle problem that I want to spend a moment on, because it explains something that I think most residential customers are about to start noticing without understanding why.

In Post 3, I described how hyperscalers are increasingly building their own behind-the-meter generation rather than relying on the public grid. Roughly forty gigawatts of announced private generation, dedicated to specific data center projects, going up outside the regulated utility planning process.

When a large customer leaves the grid, or never connects to it in the first place, that customer stops contributing to the cost recovery base that the utility uses to maintain its infrastructure. The transmission lines, the substations, the distribution network, the customer service systems, all of these have fixed costs that have to be paid for somehow. The utility traditionally recovers those costs across all of its customers, with the largest customers paying the largest share.

If the largest customers leave, the fixed costs don’t go away. They get redistributed across the customers who remain. Which is you and me.

This is not hypothetical. It is already a contested issue in rate cases in several states with significant data center buildout, where residential customer advocates are pushing back against rate increases that effectively transfer infrastructure costs from large commercial customers to residential ones. The legal and regulatory mechanisms here are complicated, but the basic dynamic is simple: when the biggest customers exit, the remaining customers carry more of the fixed cost burden, even if their own electricity usage hasn’t changed.

The Trump administration introduced something called the Ratepayer Protection Pledge in March of this year, which is intended to push some of the infrastructure costs back onto the hyperscalers that are driving demand growth. Whether it actually accomplishes that is going to depend on how state regulators interpret and implement it, which is going to vary state by state. The fundamental tension, that the public grid is increasingly being asked to socialize costs that benefit private corporations, is not going away.

What rate design is going to look like

The combination of rising capacity costs and shifting fixed-cost recovery is going to push utilities toward more aggressive rate designs for residential customers. Not because utilities are villainous, but because the math of running a grid in this environment forces it. There are a few patterns that I expect to see become more common, and that I think are worth understanding now rather than being surprised by later.

The first is the expansion of time-of-use pricing. Right now, most residential customers are still on flat rates, where you pay the same per kilowatt-hour regardless of when you use it. The Ultimate Saver plan I’m on, which differentiates between on-peak and off-peak hours, is still a minority choice in most utility territories. That is going to change. As the difference between peak and off-peak costs grows, utilities will increasingly push customers toward time-varying rates, sometimes by making them the default option and requiring customers to opt out rather than opt in.

The second is the introduction of demand charges for residential customers. Demand charges have historically been a commercial and industrial customer concept. The Ultimate Saver plan applies them to residential customers, which is unusual today but probably not unusual in five years. As more customers shift to time-of-use rates, the utility’s incentive to also charge for peak demand, not just peak energy usage, grows. Expect to see this spread.

The third is dynamic pricing, sometimes called critical peak pricing or real-time pricing. This is where the price of electricity varies not just by time of day on a fixed schedule, but in response to actual grid conditions. On extreme demand days, when the grid is genuinely stressed, the price spikes, sometimes dramatically, for a few hours. Customers who can shift their usage during those hours save significant money. Customers who can’t, or who don’t pay attention, get hit with bills that can be five or ten times what they would have paid otherwise.

The fourth is more granular metering and pricing in general. Smart meters, which have been deployed across most of the country over the past decade, enable rate structures that simply were not possible before. Most utilities have only begun to take advantage of what those meters can support. That’s going to change.

None of this is automatically bad. The reason these rate structures exist is that they more accurately reflect the actual cost of serving each customer. A flat rate hides the cost of peak capacity behind an averaged price. Time-of-use rates and demand charges make those costs visible. For customers willing to engage with the structure, the result can be a lower bill. For customers who don’t engage, the result can be a higher bill, sometimes much higher.

What you can actually do

I’m going to be honest about this part: the things ordinary ratepayers can actually do to manage what’s coming are limited. The fundamental dynamics of capacity prices, infrastructure cost recovery, and grid stress are not going to be solved by individual residential decisions. But there are a few things that are within your control, and they’re worth doing.

The first is to actually look at the rate plans your utility offers. Most utilities have several rate plans available, and the default plan is almost never the optimal one for any specific household. If your utility offers a time-of-use plan or a demand-charge plan, look at it carefully. Estimate what your bill would have been under each option, using your actual usage data, which most utilities will provide on request. The right plan for your household depends on your specific load profile, and you cannot pick the right plan without looking.

The second is to learn your own load profile. When does your house actually use the most electricity? What’s running at 7 PM on a hot Tuesday in July? What’s running at 11 PM on a Sunday in March? Most people have no idea what their actual usage pattern looks like, and they are surprised when they look. Your utility’s customer portal almost certainly provides hourly usage data going back at least a year. Spend an hour looking at it. You will learn things about your house that you did not know.

The third is the behavioral shifts I started this series with. If your utility’s rate structure rewards off-peak usage, the shift is small and the savings are real. Running the dishwasher at 10 PM instead of 7 PM. Doing laundry on weekends. Pre-cooling the house before peak hours in summer. None of this is dramatic. None of it requires equipment upgrades or lifestyle compromises. It just requires paying attention.

The fourth, and the one that I think most residential customers will never do but that genuinely matters, is to engage with the regulatory process. Rate cases happen in every state, multiple times per year, with very little participation from residential customers. The people who do show up, ratepayer advocates, large commercial customers, environmental groups, are the ones whose interests get represented in the final outcome. If you have strong opinions about how the costs of the grid should be allocated, the place to express those opinions is in your state’s public service commission proceedings. They publish notices. They accept public comment. Almost no one reads the notices or submits the comments.

Bringing it home

I started this series with a small thing. A rate plan. A dishwasher. A question about why 10 PM specifically.

What I learned in the process is that the grid is bigger and more delicate and more interesting than I had any idea, and that the system it has to serve is changing faster than it can adapt to. The story I told across these four posts is not a hopeful one, exactly. It is not a hopeless one either. It is a description of a complicated piece of infrastructure trying to handle a new set of demands under regulatory rules that were not designed for them.

The dishwasher decision is still a small thing. It saves me maybe twenty dollars a month, on a good month. The grid is going to keep working, mostly, for most people, most of the time. The buildout I described will probably resolve into something stable eventually, although the path between here and there is going to be bumpier than most people expect, and the costs are going to be distributed in ways that are not particularly fair.

What I take away from writing this series is that paying attention is genuinely useful, both to my own bill and to my own understanding of the world I live in. Most of us are connected to a continental-scale machine that we know almost nothing about, that is going through the biggest stress test in its history, and that we are nonetheless going to keep depending on for everything we do. The least I can do is know what’s on the other side of my wall outlet.

That, in the end, is what my electric bill taught me.

Thanks for reading.

This concludes the four-part series. If you want to revisit any of the previous posts: Part 1 is here, Part 2 is here, Part 3 is here.

June 7, 2026
The Grid Behind the Grid

Part 2 of a series on what I learned by accident when I started paying attention to my electricity bill.

After Post 1 went up, the question I couldn’t stop turning over was this: if the 10 PM cutoff on my Ameren bill maps to actual physics on a continental-scale grid, then what does that grid actually look like? Not in a metaphorical sense. Mechanically. What is the thing on the other side of my wall outlet, and how does it stay running?

I went looking, and the answer turned out to be more remarkable than I expected, and also more fragile than I expected. By the end of what I learned, I had stopped thinking of the grid as a robust piece of infrastructure that occasionally fails, and started thinking of it as something closer to a precision-balanced machine that succeeds every day for reasons that aren’t obvious until you understand them.

This post is about that machine. It’s also about the time it almost broke, what we did to prevent that from happening again, and why something very similar is now happening on purpose, at scale, in ways that the people building it may not fully appreciate.

A bicycle, going exactly ten miles per hour

The single most useful way I’ve found to think about how the grid works is this:

Imagine you’re riding a bicycle, and someone tells you that you must maintain exactly 10 miles per hour. Not 9.99, not 10.01. Exactly 10. Forever. The route ahead has hills you can’t see coming. When the road slopes up, you have to pedal harder. When it slopes down, you have to ease off, or maybe even brake. And if at any point you drift more than half a percent off speed, the bicycle disintegrates.

That’s the grid.

The “speed” in this metaphor is frequency. In North America, the grid runs at 60 cycles per second, also written as 60 Hz. Every generator on the grid spins at exactly this frequency, all the time. The frequency is the speed of the bicycle, and it has to stay locked at 60 Hz the way the bike has to stay locked at 10 mph.

What makes this difficult is the hills, which are changes in demand. Every time someone turns on an air conditioner, opens a refrigerator, or starts a dishwasher, the grid encounters an uphill. The bicycle has to pedal harder. Every time someone turns off a load, the grid encounters a downhill, and has to ease off. And all of this is happening continuously, across millions of customers, every second.

Grid operators tolerate about ±0.05 Hz of deviation from 60 Hz before they start getting nervous. That’s about 0.08% off speed. If the frequency drifts beyond roughly ±0.5 Hz, less than 1% off, protective equipment starts tripping generators offline to keep them from damaging themselves. That’s the bicycle disintegrating. Once a few generators trip, the remaining ones have to carry their load, which usually pushes frequency further out of bounds, which trips more generators. The cascade can run faster than anyone can intervene.

So the bicycle has to stay at exactly 10 mph, on terrain it can’t see, with a margin of error under one percent, or it falls apart.

Now imagine the bicycle is the size of a continent.

Half a continent, in perfect sync

The grid I’m part of, here in Missouri, is connected to a synchronous network called the Eastern Interconnection. It covers everything from the Rocky Mountains east to the Atlantic, plus most of eastern Canada. Roughly 39 states and 5 Canadian provinces.

Every generator in that footprint, from a nuclear plant in Florida, to a coal plant in Ohio, to a wind turbine in Manitoba, to the natural gas plant down the road from my house, is spinning at exactly the same frequency, in exactly the same phase, every second of every day.

That sentence took me a while to absorb when I first read it. Not approximately the same frequency. Not averaged over a minute. Right now, this exact second, hundreds of thousands of rotating machines spread across thousands of miles are all turning together in perfect synchronization. If they fell out of sync, the system would tear itself apart in seconds.

This is achieved through what’s called synchronous coupling. When a generator is connected to the grid, the grid itself acts like a giant flywheel pulling it into line. A generator trying to speed up gets resisted by the inertia of every other generator. A generator trying to slow down gets pulled back by them. All those spinning turbines are mechanically locked together, by electromagnetism, into a single coordinated machine the size of half a continent.

That machine is what we mean when we say “the grid.” Not the wires. The wires are just the connections between the rotating parts of the bigger machine.

The thing that coordinates the bicycle

Coordinating this machine in real time is the job of regional grid operators. The one that handles my electricity is called MISO, the Midcontinent Independent System Operator. MISO doesn’t own generators or transmission lines. It’s a coordinator, a market operator, and a referee.

What MISO does, in simplified terms, is run an auction. Every five minutes, MISO collects bids from generators across its footprint, fifteen states’ worth of them, and figures out the cheapest mix of plants to run to meet projected demand for the next five minutes. The cheapest generation wins. That coal plant in Illinois, that wind farm in Iowa, that gas plant in Louisiana, all bidding into a single market that picks the lowest-cost combination.

Underneath that five-minute market is something faster and more nervous. Every four seconds, MISO sends signals to specific generators telling them to ramp up or down a little, to keep the system frequency locked at 60 Hz. This is called Automatic Generation Control, and it’s how the bicycle stays at exactly 10 mph in real time. If frequency starts drifting up, MISO tells some generators to ease off. If it drifts down, MISO tells others to push harder.

And underneath that, faster still, is the inertia of the machines themselves. When a sudden change hits the grid, the spinning mass of every connected generator absorbs the shock automatically, for the first few seconds, before any human or computer can react. That stored kinetic energy is what gives operators time to respond at all.

So the grid is layered. Spinning inertia handles the millisecond response. AGC handles the four-second response. The five-minute market handles the minute-to-minute economic dispatch. Human operators handle the longer-term decisions about which plants to bring online or shut down across hours and days.

It works, almost all of the time. But not always.

The seven seconds it almost all came apart

On August 14, 2003, a transmission line in northern Ohio sagged in the heat of an afternoon and touched a tree. That single point of contact tripped the line offline. On most days, that’s a routine event. The grid is designed to handle the loss of any single component without cascading failure.

But on this particular day, the monitoring software at FirstEnergy, the Ohio utility responsible for that section of grid, had crashed. Operators didn’t know the line had failed. They didn’t take corrective action. Power that had been flowing on the tripped line had to find another path, so it flowed onto adjacent lines, overloading them, until they tripped too. Now more lines were down, and the remaining ones had to carry even more power, until they tripped, until a 3,500 megawatt power surge slammed across the regional grid in a direction operators hadn’t planned for.

What happened next is one of the strangest and most important things I learned in all of this.

The grid didn’t fail because it ran out of electricity. There was plenty of generation. What collapsed was something more subtle. As lines tripped offline, the ones still standing couldn’t sustain the voltage that the system needed to keep functioning. Voltage started sagging across the region. Generators saw the sagging voltage and started disconnecting themselves to avoid being damaged.

Within seconds, the cascade of generators tripping offline created the very crisis the system was designed to avoid. The grid depended not only on real power, but on something called reactive power, an invisible supporting force that maintains voltage across the transmission system and allows electricity to actually flow. When reactive power support failed, the grid could no longer deliver electricity to customers, even though plenty of real power was still being generated.

The cascade ran across the Northeast in about seven seconds. By the time it stopped, 265 power plants had shut down, over 500 generators had tripped offline, and 55 million people from Detroit to New York to Toronto were in the dark. It took several days to fully restore service.

The lights went out, not because we ran out of electricity, but because we ran out of the ability to deliver it.

What we did about it, and what we missed

The 2003 blackout fundamentally changed how the North American grid is regulated. Before 2003, the reliability standards that grid operators followed were voluntary. After 2003, the U.S. Energy Policy Act of 2005 made those standards mandatory and enforceable, with serious financial penalties for violations. The body that writes those standards, NERC, the North American Electric Reliability Corporation, gained real teeth.

The grid genuinely got more robust. Better monitoring. Better automated controls. Sensors called synchrophasors that measure grid state thirty times per second across thousands of locations. Operators today have visibility that operators in 2003 could not have imagined.

We have not had another 2003-scale cascade in the Eastern Interconnection in the more than twenty years since. That’s not nothing. That’s a real achievement.

But the regulators built that achievement to defend against a particular kind of failure. The 2003 cascade started with a tree branch and a software bug. The whole regulatory regime is oriented toward preventing transmission failures from cascading into voltage collapses.

It is not oriented toward what happens when a brand new category of customer voluntarily disconnects from the grid in milliseconds, in coordinated waves, by design.

The thing that already happened, that no one told you about

On July 10, 2024, in northern Virginia, a piece of relatively routine grid equipment failed. A surge arrester, a device that protects transmission lines from voltage spikes, malfunctioned on a 230 kV line. The transmission line itself didn’t go down catastrophically. The system handled the equipment failure the way it was designed to: it briefly dipped the voltage on that line a few times in rapid succession, called a multi-shot reclose, while the line attempted to recover.

This is the kind of event that happens dozens of times a year on the U.S. grid. Operators barely notice. The grid absorbs the disturbance and moves on.

Except this time, sixty data centers were watching.

The data centers detected the brief voltage dips and, doing exactly what their internal protection systems were designed to do, instantly disconnected themselves from the grid and switched over to their on-site backup power. All of them. In milliseconds. Across twenty-five different substations.

The total load that vanished from the grid in that moment was about 1,500 megawatts. The equivalent of three large power plants suddenly going offline, except in reverse: instead of generation disappearing, customers disappeared. The grid suddenly had 1,500 megawatts of generation with nowhere to send it. Frequency started climbing. Automated controls had to scramble to dial back generation across the region before something worse happened.

This event was not widely reported in the general press. It was the subject of a January 2025 NERC incident review that I doubt anyone outside the industry has read. But here is what NERC concluded from it: the way large data centers behave during routine grid disturbances was not anticipated by the planning studies, and current grid stability margins may not be sufficient to handle this new class of customer at the scale they are about to be deployed.

In May of this year, NERC issued a rare Level 3 alert, the kind of alert reserved for genuinely serious grid reliability concerns, warning that uncoordinated disconnections of large computational loads pose a stability threat to the bulk power system. NERC simulations have suggested that a coordinated disconnection of 2,000 megawatts of data center load, well within the size of a single planned hyperscale campus, could destabilize 20 percent of the Eastern Interconnection. Fifty million people could lose power.

That is the same scale of blackout as 2003. From the same kind of mechanism: a voltage disturbance, cascading. Except this time, the trigger wouldn’t be a tree branch. It would be a hyperscaler’s protection equipment doing exactly what it was designed to do.

Where this is going

I started this post by saying I had stopped thinking of the grid as robust infrastructure and started thinking of it as a precision-balanced machine. I want to be careful about what I mean by that. The grid is not on the edge of collapse. It works, every day, with extraordinary reliability, because of decades of engineering and regulatory effort. The bicycle stays at 10 mph.

But the conditions the bicycle has to ride through are changing faster than the bicycle is being upgraded. The grid was built and regulated for a world where customers consumed power smoothly and predictably. We are now connecting customers, very large ones, who consume power in ways that the grid was not designed to handle, and we are doing so at a pace that grid planners cannot keep up with.

Next Sunday, I want to write about the scale of what’s coming. Not the Virginia incident, but the buildout that’s about to dwarf it. Hyperscalers are no longer building data centers in tens of megawatts. They are building campuses in gigawatts. Plural. And they are building these campuses faster than the grid that’s supposed to serve them can be expanded.

The result is a collision that’s just starting to play out, with implications that are going to reach all the way to your electric bill. I’ll get into it next week.

Next Sunday: Why AI Might Not Get the Power It Needs. The collision between the AI data center boom and a grid that can’t keep up.

May 24, 2026
What My Electric Bill Taught Me About the Coming Grid Crisis

Part 1 of a series on what I learned by accident when I started paying attention to my electricity bill.

It started with a dishwasher.

Earlier this year, I switched my Ameren Missouri service over to a rate plan called Ultimate Saver. The pitch was straightforward: pay less for electricity if you can shift your usage away from peak hours. I’m not particularly frugal, but I’m curious about systems, and the structure of the plan was interesting enough that I wanted to understand it.

What I didn’t expect was that trying to figure out when to run my dishwasher would pull me into a rabbit hole about how the entire North American power grid works, and into a slowly unfolding crisis that I think most people don’t realize is happening.

This is the first of four posts about what I found. It starts small, with my own electric bill, and gets progressively bigger from there. By the end of the series I’ll be writing about why the AI data center boom is colliding with physical reality, and what that means for everyone who pays an electric bill.

But first, the dishwasher.

The plan that made me think

Ultimate Saver has two parts that work independently of each other, which took me a while to untangle.

The first part is time-of-use energy pricing. On weekdays, electricity costs more during two on-peak windows, 6 to 8 AM and 6 to 8 PM, and less during all the off-peak hours in between and around them. Weekends are entirely off-peak. So far, so simple: don’t run the dryer during dinner on a Tuesday.

The second part is a demand charge. This one is weirder. Once a month, Ameren looks at every single hour of my electricity use between 6 AM and 10 PM, every day of the month, weekends included, and finds the one hour where I drew the most power. Whatever that peak hour was, in kilowatts, gets multiplied by a per-kW rate and added to my bill. One bad hour can dominate the demand charge for the entire month.

When I first read this, I thought it was a gimmick. After spending some time with it, I think it might be one of the more honest pricing structures a utility has ever offered me.

Here’s why. The cost of providing electricity isn’t really about how much energy you use over a month. It’s about how much capacity the grid has to maintain to serve you when you need it. A house that uses 1,000 kilowatt-hours spread evenly across a month is much cheaper to serve than a house that uses the same 1,000 kilowatt-hours but spikes hard for a few hours every evening. The first house lets the utility size its infrastructure to a steady average; the second house forces the utility to build for the peak and let that capacity sit idle most of the time.

A demand charge takes that hidden reality and makes it visible. The price signal it sends is, basically: please don’t all hit the grid at once.

Figuring out my own house

Once I understood the structure, I started thinking about my own appliances. The big draws in a house like mine are the air conditioner, the electric dryer, the dishwasher (especially the heated dry cycle), the oven, and to a lesser extent things like the microwave.

The AC was the puzzle to start with, because in summer it runs almost constantly. But here’s the thing about my thermostat: it’s set to 74°F during the day and drops to 70°F at 10 PM, when we go to bed. That means the AC’s most intense work, the pulldown from 74 to 70, happens right at 10 PM, the exact moment the demand-tracking window ends. The AC’s biggest single hour of the day falls outside the window that gets billed.

So my real demand exposure during cooling season is the AC holding 74°F somewhere in the late afternoon, plus whatever else I happen to run on top of it. The pulldown is free.

This made everything else simpler. If the AC’s contribution to demand is roughly fixed during the day, then the question becomes: what else am I stacking on top of it, and when?

The dryer and the dishwasher, it turns out, are completely flexible. Nobody cares whether the dishwasher runs at 8 PM or 11 PM. Nobody cares whether the dryer finishes at 7 PM or 1 AM. These are appliances we treat as “run them whenever,” but their actual draw is significant. The dishwasher’s heated dry cycle and the dryer’s heating element are both heavy loads. Running them on top of an AC that’s already working hard in the late afternoon is exactly the kind of stacking that sets a new monthly demand peak.

So I started running them after 10 PM. The dishwasher gets loaded throughout the evening and I just start it on my way to bed. The dryer is less convenient but still workable.

It’s not a dramatic lifestyle change. It’s a small habit shift. But it removes both appliances from demand tracking entirely, and it captures the off-peak energy rate, which is a fraction of the on-peak rate. Two benefits for one decision.

The question that broke the dam

After a few weeks of this, a question started bothering me.

Why 10 PM?

The number is so specific. Not midnight, not 9 PM, not the time the sun sets. 10 PM, every day, weekends included. It’s the same number that ends the demand window and roughly the same time the on-peak energy pricing ends on weekdays. Ameren clearly chose it for a reason. But what reason?

The easy answer is “that’s when people go to bed.” But that’s not really an answer. Lots of people don’t go to bed at 10 PM. And anyway, why would a utility care exactly when its individual customers go to bed? Utilities don’t bill at the individual scale; they think in aggregate.

The real answer, I started to suspect, had to do with the grid itself.

So I went looking.

What I found when I looked at the actual data

Ameren Missouri is part of a regional grid operator called MISO, the Midcontinent Independent System Operator. MISO coordinates electricity across 15 states and one Canadian province, from Minnesota down to Louisiana. They publish real-time operational data on their public website: how much electricity is being generated, where it’s coming from, how it’s flowing between regions, what the forecast looks like for tomorrow.

I pulled their load curve for a normal weekday this spring. The shape of it is striking. Demand bottoms out around 4 AM at roughly 58,000 megawatts across the entire MISO footprint. It starts climbing around 6 AM as people wake up, grows steadily through the morning and afternoon, peaks around 6 to 7 PM at about 88,000 megawatts, and then, here’s the part that mattered to me, drops fast.

By 8 PM, load is down 3,000 megawatts from peak. By 9 PM, it’s down 6,000. By 10 PM, it’s down 10,000. By 11 PM, it’s down 14,500 megawatts from the evening peak.

Between 6 PM and 10 PM, the grid sheds roughly the equivalent of an entire nuclear fleet’s worth of demand. By the time the demand-charge window closes at 10 PM, the grid has genuinely entered a different operating regime. Expensive natural gas peaker plants that had to fire up to meet the evening peak can throttle back. Cheaper baseload generation, nuclear, coal, wind, handles the overnight load comfortably. The system is no longer stressed.

That’s why 10 PM. It’s not about when I go to bed. It’s about when the grid as a whole stops needing to scramble. The number maps to physics, not to convenience.

When I saw that, really saw it, in the actual hourly data, something shifted for me. The rate plan stopped feeling like a marketing structure and started feeling like a window into a real system. My dishwasher decision was a tiny instance of a much larger problem the grid is constantly solving.

And the closer I looked at that larger problem, the more interesting it got. And the more concerning.

Where this is going

I want to tell you what I found, because I think most people have no idea how much is changing right now in the systems that quietly power their lives.

Over the next three Sundays, I’ll be posting the rest of this series.

Next week, I’ll write about what MISO actually does. How a continental-scale power grid manages itself in real time, what the 2003 Northeast Blackout taught us about how this can fail, and why every appliance you own is connected to a machine spanning half a continent that has to stay in perfect synchronization, every second of every day.

The week after, I’ll get into what I now think is the most important undercovered story in the country: the collision between the AI data center boom and the physical infrastructure that has to power it. The companies building these data centers are starting to give up on the public grid entirely, with consequences that will eventually show up on your electric bill, whether you’ve heard about any of this or not.

And in the final post, I’ll bring it back to where this started. What all of this means for someone like me, an ordinary Ameren customer running a dishwasher at 10 PM, and what we can actually do about it.

I didn’t expect to spend this much time thinking about my electricity. But the more I understand about the system on the other side of my wall outlet, the more I think it’s one of the most important things I’ve ever paid attention to.

The dishwasher was just the beginning.

Next Sunday: The Grid Behind the Grid. What MISO actually does all day, and why the lights have to go out exactly as often as they do (which is more often than you think).

May 17, 2026