Mike Howells's Blog

Tag: electricity demand

  • The Day 4,500 Megawatts Disappeared

    The Day 4,500 Megawatts Disappeared

    It started with a notification at 9:07 AM.

    I run a small script that collects data from MISO, the Midcontinent Independent System Operator, the organization that runs the bulk electric grid for 45 million people across the middle of the continent, from Manitoba to the Gulf of Mexico. My house in eastern Missouri sits inside its footprint. I am not a grid operator. I am the person who wanted to understand what the numbers on my electric bill actually meant, and who kept pulling on that thread until it led here. On the morning of Wednesday, July 15, the thread pulled back.

    The notification was a Maximum Generation Warning, published at 9:07 AM ET. In MISO’s vocabulary, a Warning means the grid operator believes that every economic power plant it can call on will be committed to meet demand, and it is concerned about holding the required safety cushion of reserves on top of that. It is not an emergency. It is the announcement that the emergency toolkit is being taken down off the shelf. The Warning would not even take effect until 2:00 PM ET. The most dangerous grid day of the summer had announced itself at breakfast.

    By dinner, MISO would be in the first Energy Emergency Alert Level 2 it has ever declared in the heart of summer. This post is about what actually happened in between, told from data I archived while it was happening. The story the numbers tell is not quite the story the headlines told.

    MISO’s footprint, approximately. The July 15 declarations covered the North and Central Regions; the South Region was never under them.

    The view from outside

    If you watched the news that evening, you saw a simple story. Record heat. Air conditioners straining. A grid pushed to its limit by demand. All of that is true as far as it goes. It was brutally hot across the entire middle of the country, and demand did crest at 122,627 megawatts at 4:15 PM ET, roughly 4,500 megawatts shy of MISO’s all-time record of 127,125 MW, set on July 20, 2011. For scale, a house running its air conditioner flat out on an afternoon like this draws around five kilowatts, which makes one megawatt about 200 homes at full blast. The 1,000 homes per megawatt figure you sometimes see quoted is an annual average, not a peak number.

    But heat was the stage, not the plot. To see the plot, you need to look at the supply side of the ledger, and you need to look at it twice in the same day.

    The ladder

    First, a map of the territory. MISO’s emergency procedure is a ladder, and as of June 1 of this year it has three numbered rungs, each aligned with a federal emergency level called an Energy Emergency Alert, or EEA. Below the numbered rungs sit the preliminary postures, the Warning among them. Step 1, which is EEA1, unlocks the emergency operating ranges of the generation fleet, squeezing megawatts out of plants beyond their normal comfortable maximum. Step 2, which is EEA2, is the big one short of disaster. It opens the full toolkit: load modifying resources (large customers who have agreed, in exchange for payment, to cut their usage when the grid calls), emergency purchases from neighboring grids, and public appeals for conservation. Step 3 is EEA3. That is the level where rotating outages become possible, and even then, in MISO’s own words from the procedure revision, load shedding is “not necessarily automatic.”

    Here is how July 15 climbed it. Every declaration was published hours before it took effect, which is worth pausing on. A capacity emergency, unlike a storm, arrives by appointment.

    • 8:53 AM ET. MISO updates a Conservative Operations declaration that had already been in effect since Monday, citing hot weather and a tightening reserve margin. Conservative Operations is the grid equivalent of a hospital canceling elective surgeries, deferring non-essential maintenance to keep every resource available.
    • 9:07 AM ET. The Maximum Generation Warning is published, effective 2:00 PM ET, for the North and Central Regions. Reasons given, in order: forced generation outages, above normal temperatures, higher than forecasted load.
    • 11:12 AM ET. Maximum Generation Event Step 1, EEA1, published. Effective 3:00 PM ET.
    • 2:19 PM ET. Maximum Generation Event Step 2, EEA2, published. Effective 5:00 PM ET, scheduled to run to 9:00 PM ET. Emergency Tier II pricing implemented.
    • 6:20 PM ET. The step back down begins. A return to EEA1 is published, effective 6:30 PM ET.
    • 6:52 PM ET. A further step down to Warning is scheduled for 7:30 PM. One minute later, at 6:53 PM, MISO cancels that schedule. The operators wanted another look.
    • 7:46 PM ET. The step down to Warning is issued, effective immediately.
    • 8:48 PM ET. MISO publishes the termination, effective 9:00 PM ET, seventy-two minutes before the 10:00 PM end it had on the schedule.

    Zero customers were interrupted. The emergency ended early, in an orderly walk back down the same ladder it had climbed.

    3:00 PM ET: EEA1 in effect, marginal energy at $124.61. (The dashboard clock reads 2:00 PM EST; MISO labels its displays EST year-round, an hour behind Eastern in summer.)
    5:00 PM ET: the EEA2 declaration takes effect. The needle steps into the dark orange and marginal energy has tripled to $388.85. (Dashboard clock: 4:00 PM EST, same labeling convention.)

    What the ledger said, morning and afternoon

    Now the part that did not make the news.

    My script pulls MISO’s public data on a schedule, and on July 15 I also pulled it by hand at moments that turned out to matter. One of the feeds is the generation outage table, which reports how many megawatts of power plant capacity are unavailable, split by category. A forced outage is the involuntary kind. A unit that breaks, or derates in the heat, or trips offline. Not maintenance that was scheduled months ahead. The broken-leg category, not the scheduled-surgery category.

    Three snapshots of the same number, the forced outage megawatts for July 15 itself:

    • Two days ahead (July 13 pull): 8,231 MW expected
    • Morning of, 9:40 AM ET: 10,978 MW
    • Afternoon, 3:10 PM ET: 15,453 MW

    Between breakfast and mid-afternoon, 4,475 megawatts of generation moved onto the forced outage list. That is roughly the output of four large power plants, subtracted from the supply side of the ledger in the hours when the day was already at its tightest. Counting all categories, total unavailable capacity went from 31,395 MW in the morning pull to 36,231 MW in the afternoon pull. And compared with what the forward-looking view had expected just two days earlier, event day delivered nearly double the forced outages anticipated.

    Meanwhile, the demand side behaved differently than the official reasons might suggest. “Higher than forecasted load” appeared on every declaration that day. My archive shows that during the emergency window itself, the opposite was true. At 3:10 PM ET, MISO’s own intraday forecast projected demand of about 122,800 MW for the late afternoon. The actuals came in at 121,699 MW at 5:00 PM, 120,458 MW at 5:30, and 120,014 MW at 6:00. Through the whole EEA2 window, demand ran 2.4 to 2.9 gigawatts below the forecast.

    I am not going to tell you what to conclude from the juxtaposition. Both things are in the record. The declarations cited forced outages first among their reasons, and the outage table shows why. The declarations also cited higher than forecasted load, and the load data shows demand undershooting the forecast throughout the emergency hours. Some of that undershoot is the emergency toolkit working, which is the next section. Some of it may be forecast conservatism on a dangerous day. The numbers are above; the reader can weigh them.

    MISO’s intraday forecast held near 122,800 MW through the emergency window. Actual demand fell 2.4 to 2.9 gigawatts below it as load modifying resources curtailed and thermostats eased upward. Source: MISO Supply and Demand feed, archived in real time on July 15; forecast series from the 3:10 PM ET pull.

    The machinery, working

    Three mechanisms carried the afternoon, and all three are visible in the data.

    The first was borrowing. MISO imported power from its neighbors all day, and by evening the net imports reached 16,854 megawatts, close to seventeen gigawatts, an extraordinary volume. The deepest borrowing came at the end of the day, after the emergency declarations had already terminated. The paperwork expired at 9:00 PM. The dependence did not.

    The second was commitment. Between 2:00 PM and 5:15 PM ET, the capacity MISO had committed and online rose from 126,783 MW to 135,308 MW. Eight and a half gigawatts added to the books in three hours, some of it those emergency operating ranges from the EEA1 declaration, some of it units racing to the field. You can watch the cavalry arrive in fifteen-minute intervals.

    The third was demand itself bending. That 2.4 to 2.9 gigawatt gap between forecast and actual during the EEA2 window is the fingerprint of load modifying resources curtailing on instruction and of ordinary people easing thermostats upward. MISO’s own after-action report, expected in the coming weeks, should put an official number on the load modifying resource deployment. I will return to it here when it posts.

    And over all of it, prices told the day’s story with brutal clarity. Wholesale electricity in MISO is priced by locational marginal price, or LMP, the cost of serving one more megawatt at a given place and time. At Indiana Hub, the benchmark trading location, the hourly real-time price opened the day near $35, sat at $49 during breakfast, and climbed as the outage list grew: $125 by midday, $337 by early afternoon. Then something interesting happened. Prices fell back to about $175 in the very hours demand was cresting, because sixteen gigawatts of solar generation were pouring in at full strength. The emergency’s sharpest edge was never the demand peak. It was the sunset. As solar faded from 15,035 MW at 6:00 PM to 7,726 MW by 8:00 PM, with wind delivering only 1,700 to 1,900 MW all evening, the price staircase went vertical: $405, $620, $806, and finally $959 for the hour ending 9:00 PM ET. The hour after termination, it was $72. From nearly a thousand dollars to seventy-two in a single step. By the day’s final market hour, $49, almost exactly where it began.

    Hourly real-time prices at Indiana Hub, MISO’s benchmark trading location. The climb tracks the evening solar fade, not the afternoon demand peak, and the fall from $959 to $72 lands exactly at the 9:00 PM ET termination. Source: MISO’s preliminary real-time market report for July 15, 2026.

    How close was the real emergency?

    The question my neighbors asked, once they learned what I watch all day, was simple. Were we close to the lights going out?

    The honest answer has three layers.

    Procedurally, EEA3 is one rung up the ladder, but the distance is bigger than one rung suggests. Inside Step 2, MISO deployed load modifying resources and emergency purchases, but it never issued formal public appeals for conservation, never drew down its operating reserves, and never made the deeper reserve call on neighboring grids. Several tools stayed in the box. EEA3 is declared when the toolkit is exhausted, and on July 15 it was not close to exhausted.

    Physically, the question is what additional failure would have been required. Wind had little left to give, delivering under two gigawatts and missing even its own modest forecast. The realistic paths downward were another multi-gigawatt block of outages stacking onto the 15,453 MW already lost, or trouble on the far side of the border, because seventeen gigawatts of imports means seventeen gigawatts of dependence on neighbors having power to spare. The borrowing that saved the day is also, candidly, the day’s soberest number.

    Historically, the record is reassuring in a specific way. In the modern record, MISO has ordered firm load shed, the deliberate interruption of customers, exactly three times. Roughly 500 MW during Hurricane Laura in August 2020, for a Louisiana pocket wrecked by transmission damage. 700 MW at the depth of Winter Storm Uri in February 2021, in the South Region. And approximately 600 MW directed around New Orleans on May 25, 2025, per MISO’s own event report, with roughly 500 MW of it landing across the metro area. All three in the South. None in the Midwest core. None larger than 700 MW on a system serving over 120,000 MW.

    That last event carries a lesson worth separating out. New Orleans did not happen at the top of the capacity ladder. It happened through a different door entirely, a transmission security emergency, where an overloaded line threatens cascading failure and operators shed load with minutes of notice rather than hours. The capacity ladder is slow and announced. July 15 was a day spent partway up that staircase, with every step published in advance. The transmission door has no staircase. Understanding which door an emergency comes through is most of understanding how much warning you will get.

    The winter rehearsal

    Here is the part that convinced me this day deserved a full write-up rather than a thread. It had already happened once this year, in the cold.

    On January 24, during Winter Storm Fern, MISO declared EEA2 for the North and Central Regions, the same two regions, the same rung of the ladder, in the same year. The parallels are almost uncomfortable. Fern’s emergency was outage-driven too, with unplanned generation outages exceeding 40 gigawatts at their peak, the overwhelming share concentrated in the North and Central regions. Fern deployed about 2 gigawatts of load modifying resources, the same scale as July’s demand response. Fern leaned on emergency purchases from PJM, the neighboring grid to the east, just as July leaned on imports.

    And one difference makes the comparison sting. During Fern, a software failure kept emergency prices from publishing for roughly eleven hours. Prices on the screens did not reflect the emergency on the ground, which meant imports were never properly paid to show up. MISO shipped the fix on February 5. The clean, vicious price staircase of July 15, the one that pulled seventeen gigawatts across the borders and then collapsed the moment the emergency ended, was that fix passing its first summer exam. In January the price signal was broken. In July it worked. The whole difference between those two sentences is invisible to anyone whose lights stayed on, which is to say everyone, and it is one of the most consequential facts of the year on this grid.

    One year. Two seasons. Two EEA2s, same regions, same anatomy. The machine got tested in the cold, patched in February, and passed in the heat.

    What EEA3 would have looked like at your house

    Since the question deserves a concrete answer. If July 15 had gone one rung further, here is the sequence, for a reader in eastern Missouri.

    MISO computes the shortfall in megawatts and allocates a share to each local utility. Ameren receives a number. Ameren implements it through pre-engineered rotating outage plans: feeder-level blocks, typically rotating every 30 to 60 minutes so no neighborhood carries the whole burden, with circuits serving hospitals, water treatment, and emergency services flagged for exclusion where the network allows. Wholesale prices go to the Value of Lost Load, an administrative ceiling meant to represent what interrupted service actually costs. That ceiling is currently $10,000 per megawatt hour, effective September 30, 2025, nearly triple the $3,500 that applied during the Laura event. The financial deterrent got steeper between the last EEA3 and any future one, which was the point.

    And it is not hypothetical machinery. EEA3 has been declared twice on the capacity ladder in the modern record, and both declarations left a paper trail in MISO’s own emergency log. On August 27, 2020, as Hurricane Laura tore out transmission in western Louisiana, MISO declared EEA3 for the affected pocket with Value of Lost Load pricing in effect from 12:00 PM ET until nearly midnight. The log records 300 MW of load shed ordered at 1:02 PM ET, another 200 MW at 2:22 PM ET, and termination once transmission returned to service. On February 16, 2021, at the bottom of Winter Storm Uri, MISO declared EEA3 for the South Region at 7:40 PM ET and requested 700 MW of firm load shed ten minutes later. That declaration ran until 1:00 AM ET. In both cases, what customers experienced on the ground was the rotating-outage machinery described above, implemented by their local utilities, lasting hours rather than days, and lifted the moment conditions allowed.

    It is machinery. Rehearsed, bounded, and used briefly, and never here. That is not a promise. It is a base rate.

    The record, stated precisely

    Claims like “first” deserve receipts, so here are mine. Against MISO’s own compiled declaration log covering 2009 through mid-2024, and against the individual records for every season since, July 15, 2026 was the first NERC EEA2 declared during MISO’s June-through-August summer season in the modern record. It was declared for the North and Central Regions, not the full footprint. The honest footnotes: MISO reached the equivalent market step without a NERC EEA2 declaration on June 10, 2021 and August 24, 2023, and a South Region EEA2 occurred on September 15, 2018, summer by the calendar though outside MISO’s June-through-August planning season. The nearest EEA2 in time was not years ago. It was January.

    Summer capacity emergencies used to be a thing MISO wrote procedures about and winter storms delivered. As of this year, both seasons have produced one.

    Yellow, not green

    At 9:00 PM ET the declarations expired. My dashboard gauge did not go green. It went yellow, because Conservative Operations remained in effect through the end of the week, and out at the borders the imports were still running at their daily maximum after the emergency ended. The paperwork closed. The posture did not.

    In the series that started with my electric bill, I argued that the margins on this grid are thinning, and that the interesting question is not whether the emergency toolkit works. July 15 is what a thinning margin looks like when the toolkit works: four large power plants’ worth of supply vanishing from the ledger between breakfast and mid-afternoon, absorbed by borrowing, commitment, demand response, and a price signal doing exactly what it was built to do, ending seventy-two minutes ahead of schedule with nobody’s lights out.

    The toolkit worked in January. It worked in July. The question the data cannot answer, and the one worth sitting with, is how many times in a row it has to.

    Fediverse Reactions
  • Why AI Might Not Get the Power It Needs

    Why AI Might Not Get the Power It Needs

    Part 3 of a series on what I learned by accident when I started paying attention to my electricity bill.

    In Post 2, I wrote about the grid as a precision-balanced machine and ended with the Virginia 2024 incident, in which sixty data centers disconnected themselves from the grid in milliseconds because of a routine equipment fault, dumping 1,500 megawatts of load that the system had to scramble to absorb. I said the event was a preview of something larger that’s already underway.

    This post is about that something larger.

    The thing I want to convey here is hard to convey because the scale is genuinely difficult to grasp. The AI buildout that’s happening right now, in 2026, is not an evolution of the previous data center industry. It’s a different category of thing, growing at a different rate, with different operational characteristics, and the existing grid was not built for it. Neither were the rules governing it.

    I am going to try to explain how big this is, why the grid can’t keep up with it, what the companies building it are doing in response, and why none of the official solutions are likely to work in time.

    The size of the thing

    The previous generation of data centers, the ones that hosted your email and your cloud storage and your video streaming, drew power in the tens of megawatts. A typical large data center campus, in 2018, might have pulled 40 to 80 megawatts. That was a substantial customer for a regional utility but not a transformative one.

    AI training data centers operate at a different order of magnitude. A single hyperscale AI campus today is being designed for one to two gigawatts of power draw. Plural gigawatts. That is, one to two thousand megawatts per campus. Per campus.

    To put a single gigawatt in context: it is roughly the power output of a large nuclear reactor. It is also roughly the average power consumption of a city of half a million people. When a hyperscaler builds a one-gigawatt AI training facility, they are building, from the grid’s perspective, the equivalent of dropping a small city onto the system, in one location, all at once.

    And they are not building one campus. Microsoft, Google, Amazon, Meta, and Oracle are each building multiple multi-gigawatt campuses, simultaneously, across multiple states. Then there are the OpenAI and xAI and CoreWeave and other dedicated AI infrastructure companies doing the same. And the regional utilities, all of them, are receiving interconnection requests for these campuses faster than they can process them.

    Projections of how much electricity AI will consume by 2030 vary, but the credible range is roughly 300 to 500 terawatt-hours of new annual demand in the United States alone. The lower end of that range is bigger than the entire electricity consumption of California. The higher end is bigger than the entire electricity consumption of Germany. Either way, what we are talking about is adding the equivalent of one of the largest power-consuming economies in the world to the existing U.S. grid, in five years.

    This was not in any utility’s planning model as recently as 2022.

    The queue that never empties

    When a new generation project or a new large customer wants to connect to the grid, they don’t just plug in. They enter what’s called an interconnection queue. The utility studies whether the existing transmission system can handle the new connection, identifies necessary upgrades, calculates who pays for what, and eventually issues the agreements that allow the connection to proceed.

    This process has always taken time. But the data published by Lawrence Berkeley National Laboratory, which tracks the U.S. interconnection queue, shows that it has stopped functioning at the scale it now needs to operate. The current queue contains over two thousand three hundred gigawatts of proposed projects. That is roughly double the entire installed generation capacity of the United States. The queue contains, in proposed form, a second United States grid.

    But the queue does not turn proposals into operating projects. Of all the projects that entered the queue between 2000 and 2019, only about thirteen percent had reached commercial operation by the end of 2024. The rest were withdrawn, cancelled, or still waiting after years of review.

    Even projects that do get built spend an average of about five years in the queue before they begin operating. That number has been getting worse, not better, over the past fifteen years.

    For a hyperscaler trying to build a data center that needs to be operational in 18 to 24 months, this is a structural impossibility. The grid expansion that would be required to serve them, on the timeline the regulated utility process can deliver, cannot happen in time. By the time the utility finishes the studies, files the rate cases, builds the new transmission line, and energizes the new substation, the data center has already been operating, or has already been abandoned.

    So the hyperscalers stopped waiting.

    Bring your own power

    Sometime between late 2024 and early 2026, the hyperscaler industry made a strategic pivot that did not get much press coverage but is going to reshape American electricity infrastructure. They decided to stop relying on the public grid to power their AI data centers.

    This is referred to in the industry as “behind-the-meter generation” or “bring your own power.” What it means in practice is that the hyperscaler builds its own dedicated power generation, on or adjacent to the data center site, and uses that generation as the primary power source. The grid connection becomes a backup, not the primary supply.

    The scale of this pivot is remarkable. As of late 2025, industry trackers were following approximately forty gigawatts of announced behind-the-meter generation tied to specific data center projects. To repeat: that is forty thousand megawatts of dedicated power plants, mostly natural gas, being built outside the regulated utility planning process, on private timelines, by companies that are not in the power business and have never operated power infrastructure at scale.

    The poster child for this strategy is xAI’s Colossus facility in Memphis, which Elon Musk built and brought online faster than any data center of comparable size in American history by deploying dozens of portable natural gas turbines on site, in many cases before the permits to operate them had been granted. The local air quality district and the Tennessee state environmental regulators have been playing catch-up ever since. Fines have been issued. Operations have continued.

    The point is not that Musk is uniquely cavalier, although he might be. The point is that the economic logic of the AI buildout makes regulatory delays unacceptable to the companies building it. A hyperscaler that waits two years for permits while a competitor builds in six months loses the AI race. The decision tree is not really a tree at all. It is a single branch: build now, deal with consequences later. Pay the fines. Settle the lawsuits. Keep the data center running.

    If you are a regulated utility trying to integrate this customer into your service territory, you are not actually negotiating with a customer. You are watching a customer build their own utility, on their own timeline, and asking you to please connect a backup line when you can.

    The rules that don’t exist yet

    The Virginia 2024 incident I wrote about in Post 2, in which sixty data centers disconnected in milliseconds, was not an isolated event. The North American Electric Reliability Corporation, NERC, has identified multiple similar incidents in both the Eastern Interconnection and the Texas grid since 2022. In each case, large computational loads have unexpectedly disconnected, in coordinated waves, in response to disturbances that the grid would normally have absorbed without incident.

    In September 2025, NERC issued a Level 2 alert about this. A Level 2 alert is a regulatory step below an emergency, asking the industry to develop better practices for handling large computational loads. The response from the industry was, by NERC’s own assessment, inadequate. Most of the entities NERC asked to develop better practices did not develop better practices.

    So on May 4, 2026, just two weeks ago, NERC escalated to a Level 3 alert. A Level 3 is the highest level of alert NERC issues. It identifies “essential actions” that grid operators and transmission planners must take to address an immediate reliability risk. NERC has not issued a Level 3 alert about large loads before. The previous Level 3 alert, issued in 2024, was about a different concern entirely, the behavior of solar and wind resources during grid disturbances.

    The current alert reflects a regulatory body that has run out of patience with the pace of industry response. NERC’s modeling, published earlier this year, indicates that the coordinated disconnection of two thousand megawatts of data center load, which is well within the operational range of a single hyperscale campus, could destabilize twenty percent of the Eastern Interconnection. That would be a blackout on the same scale as 2003.

    But here is the part that I find genuinely difficult to absorb. The Level 3 alert does not actually require data centers to do anything differently. It requires transmission planners and grid operators to study the problem, model the risks, and report back. The deadline for the initial response is August 3, 2026. The data center operators themselves are not directly bound by the alert at all.

    The reason for this regulatory gap is structural. NERC’s mandatory reliability standards apply to entities classified as part of the Bulk Electric System, which historically has meant generators and transmission operators. Data centers, even gigawatt-class ones, are classified as customers. They are bound by their interconnection agreements with their local utility, but they are not subject to the same mandatory federal reliability standards that govern, say, a nuclear power plant or a regional transmission organization.

    NERC is working on changing this. There is a process underway to create a new classification called a Computational Load Entity, which would subject large data centers to mandatory reliability standards. The estimated timeline for that process, according to industry analysts working on it, is somewhere between three and five years.

    In the meantime, data centers continue to interconnect at the pace of new construction, under existing rules, with the kind of internal protection systems that produced the Virginia 2024 incident, on an honor system that depends on the data center operator picking up the phone when the grid operator calls.

    The honor system problem

    I want to spend a moment on this, because when I learned how the current coordination between data centers and grid operators actually works, I was genuinely surprised.

    When a major grid disturbance happens and data centers trip themselves offline to backup power, the process of bringing them back online has to be staggered. If sixty data centers all reconnected to the grid simultaneously, you would create the opposite problem from the disconnection, an instantaneous fifteen-hundred-megawatt load step that the grid would have to absorb in the other direction.

    The way this is currently managed is largely by phone call. The grid operator’s control room calls the data center operations centers. They coordinate a staggered reconnection. The data centers cooperate.

    There is no technical mechanism that prevents a data center from reconnecting whenever it wants. The automatic transfer switches that physically reconnect the facility to the grid are owned and controlled by the data center, not the utility. The utility could, in an extreme case, manually open the breaker on its side of the connection, but this is a last-resort action, not an automated safety system.

    The entire system depends on the data center operator choosing to cooperate. Which has worked so far, because the operators involved have been hyperscalers with sophisticated operations teams who understand the consequences of uncoordinated reconnection and have working relationships with their grid operators. But it depends on goodwill, scaled, in an industry where the willingness to pay fines as a cost of operating quickly is a documented business strategy.

    A senior grid planner I read recently put it bluntly: the current arrangement works because the number of relevant data center operators is small enough to coordinate by phone. As that number grows, and as the diversity of operators grows beyond a handful of hyperscalers to include hundreds of smaller AI startups, colocation providers, and crypto miners, the assumption that everyone will cooperate becomes thinner.

    The collision

    So here is where we are.

    The AI industry is building data center capacity that will dwarf any new demand source the U.S. grid has absorbed in its entire history. The companies building it are doing so on private timelines, with private generation, often outside the regulated planning process, in many cases without waiting for the permits that would normally be required. The regulatory body responsible for grid reliability has acknowledged that current rules are inadequate but cannot create new rules faster than the buildout proceeds. The technical coordination between data centers and the grid is governed largely by phone calls and cooperative agreements that depend on goodwill.

    This is the operating condition of American electricity infrastructure right now. Not a future scenario. The current reality.

    The grid will not collapse next week. The grid is more resilient than this description might suggest, because of the decades of engineering and regulatory effort that went into making it resilient. But the margin of safety that grid planners used to be able to count on is shrinking, fast, and the people responsible for managing the system are publicly acknowledging that they cannot keep up with the pace of change.

    In the final post in this series, I want to bring all of this back to where we started. What does any of this mean for someone like me, a residential customer in Missouri running a dishwasher at ten PM? What is going to happen to my electric bill, and to yours? And what, if anything, can ordinary ratepayers actually do about it?

    That’s next week.

    Next Sunday: Why Your Electric Bill Is About to Get Weirder. What the AI buildout means for the rest of us, and what we can actually do.