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August 27


 

 







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THE HILL REPORT

Eleven Hours, and Eighty Percent Were Storms

Connor Hill · InsightfulWord · August 27, 2026

Grid reliability is not a matter of impression. It is measured, reported
annually by every utility to a federal agency, and published in a form anyone
can download. Two numbers carry most of the information.

The first is average interruption duration: the total time the typical
customer spent without power over a year. The second is average interruption
frequency: how many separate outages the typical customer experienced. The
industry calls them SAIDI and SAIFI, and together they describe what
reliability actually feels like at a wall socket.

In 2024 the average United States customer experienced roughly eleven hours
without power. That is nearly double the average of the preceding decade, and
the reason is unambiguous in the data: abouteighty percent of those hours came
from major weather events, principally three hurricanes. Interruptions from
everything else averaged around two hours, which is where that figure has sat
routinely for years.

That split is the whole subject, and it points somewhere other than where
discussion of grid failure usually goes. The deterioration in American
reliability is overwhelmingly a story about weather striking physical
infrastructure — poles, wires, substations, vegetation — rather than about
insufficient generation, and the two problems have almost nothing in common in
terms of what fixes them.

Generation adequacy is a real and separately assessed question, evaluated by
the reliability regulator in seasonal and long-term assessments that identify
which regions face elevated risk of shortfall under stress conditions. Those
assessments have flagged genuine concerns. They are a different document
measuring a different failure mode, and conflating the two produces confusion
in both directions.

The reason this distinction matters for anyone evaluating a claim about the
grid is that it determines which technology could possibly help. A device that
improves generation adequacy does nothing about a tree falling on a
distribution line, and vice versa.

What follows is what the two indices measure, where the outage minutes
actually originate, what the major event day exclusion does to the reported
numbers, what the separate adequacy assessments say, and what genuine
improvement would look like in the data.

What the Two Indices Measure

Both are defined in an engineering standard and calculated the same way by
every reporting utility, which is what makes them comparable.

Average interruption duration is the sum of all customer-minutes of
interruption divided by the number of customers served. It is reported in
minutes or hours per customer per year and answers the question of how much
outage time the average customer experienced.

Average interruption frequency is the number of sustained interruptions
divided by the number of customers. It answers how often, rather than how long.

Dividing the first by the second gives average restoration time per event,
which is a measure of how quickly a utility repairs faults and is frequently
more revealing about operational performance than either index alone.

Sustained is a defined term — conventionally an interruption lasting more than
five minutes. Shorter events, which are common and are increasingly
consequential for digital equipment, are counted in a separate index that far
fewer utilities report.

A third index deserves mention because it changes how the others should be
read. Average interruption duration among customers who actually experienced an
outage — as distinct from the average across all customers — is typically
several times higher than the headline figure, because most customers
experience no interruption at all in a given year while a minority experience
long ones. The population average therefore describes almost nobody's actual
year, which is the ordinary difficulty with any mean computed over a skewed
distribution.


Where the Minutes Originate

The physical architecture explains the pattern, and it is worth setting out
because it is rarely described.

Electricity moves from generators onto high-voltage transmission lines, then
to substations that step the voltage down, then onto distribution circuits that
run along streets to individual customers. Each stage has a different failure
profile.


📊 Fresh Energy Signal

11 hours, 80 percent from major events

Average electricity interruption experienced per U.S. customer in 2024 —
nearly double the preceding decade's average — with about 80 percent of those
hours attributable to major weather events, principally three hurricanes.
Interruptions excluding major events routinely average around two hours a year.
Source: U.S. Energy Information Administration, Today in Energy, annual
electric power industry reliability data.


Support or oppose: should major event days be excluded from reported
reliability?

Supporters of the exclusion argue that a single hurricane would otherwise
swamp the metric and make year-to-year operational comparison impossible, and
that the standard requires reporting both figures anyway. Opponents answer that
customers experience all outages equally, that the excluded events are exactly
the ones growing, and that a headline number omitting them understates what is
happening. Which reporting convention serves the public better?Hit reply — one
line is enough.

Transmission failures are rare and consequential, because a single line can
serve a large area. Distribution failures are common and local, because the
circuits are exposed, run at street level through trees, and are struck by
weather, vehicles and animals.

The great majority of customer interruption minutes in ordinary years
originate on the distribution system rather than in generation or transmission.
That is a fact about exposure rather than about engineering quality:
distribution networks comprise millions of miles of conductor supported on
poles, and no amount of generating capacity affects whether one of them comes
down.

The interventions that address it are correspondingly unglamorous — vegetation
management, pole replacement and inspection, selective undergrounding,
automated switching that isolates a fault and restores customers on the healthy
portion of a circuit, and better outage management systems. Every one of them
is a spending decision made in a rate case rather than a technology anyone is
waiting to be invented.

Undergrounding is the intervention most often proposed by people outside the
industry and the one with the least favorable arithmetic. Buried cable is
dramatically more expensive to install per mile than overhead conductor, and
while it is largely immune to wind and trees, it is vulnerable to flooding and
takes considerably longer to repair when it does fail. The result is fewer
outages of greater duration, which improves one index and can worsen the other.


What the Exclusion Does

The reporting standard requires utilities to publish reliability figures both
including and excluding major event days, and understanding the second is
necessary to read either.

A major event day is defined statistically rather than by cause. The standard
uses a threshold derived from the distribution of daily interruption values
over several years, and any day exceeding it is classified as major and
reported separately.

The logic is that comparing a utility's ordinary operational performance
across years is impossible if one year contained a hurricane. The exclusion
isolates the part of performance that management controls day to day.


Context — what does not follow from any of this

Nothing here indicates that generation adequacy is unimportant or that grid
investment is unnecessary. The reliability regulator's assessments identify
regions where demand growth, retirements of dispatchable capacity and
interconnection delays create genuine risk under extreme conditions, and those
are serious findings. The point is narrower: the two failure modes are measured
separately, reported separately, and addressed by different investments, and a
claim about one is not evidence about the other.

The defect is that the excluded days are the growing part. When the average
customer spends nine of eleven outage hours inside major event days, a metric
excluding them describes a shrinking share of the actual experience. Both
numbers are published; only one usually travels.


What the Adequacy Assessments Say

Generation adequacy has its own reporting apparatus and its own vocabulary,
and the two should not be mixed.

The reliability regulator publishes seasonal assessments before summer and
winter, and a long-term assessment looking out a decade. They classify regions
by risk of resource shortfall under normal and extreme conditions, using
reserve margins and probabilistic modeling.

Recent assessments have identified elevated risk in several regions, driven by
a combination of load growth, retirement of dispatchable capacity faster than
replacement, and dependence on weather-dependent generation during extreme
events. Those findings are documented and specific.

What they describe is a risk of insufficient supply during a defined stress
period — a heat wave, a deep freeze — resulting in controlled load shedding.
That is a different event from a storm knocking out a neighborhood, it has
different causes, and the interventions are different: capacity procurement,
transmission expansion, demand response, storage, and market design.

There is a third category that belongs alongside them and is measured by
neither: the transmission constraint that prevents available generation from
reaching where it is needed. That is a congestion problem rather than an
adequacy or a distribution problem, it shows up in wholesale price differences
between locations rather than in outage statistics, and it is the failure mode
most likely to be described in general terms as the grid being unable to cope.

Both problems are real. So is the third. They are not the same problem, and an
argument that moves between them without noticing is not describing anything
specific.


What Genuine Improvement Would Look Like

Four series would show whether anything is working, and all are public and
annual.

Interruption duration excluding major events, trended over five to ten years
by utility. This is the operational measure and it is the one that responds to
distribution investment.

Restoration time per event, computed from the two indices. Falling restoration
time indicates better fault location, switching and crew deployment even where
the number of faults has not changed.

Interruption duration including major events, trended over the same period,
which captures whether hardening is reducing the consequence of storms rather
than merely the ordinary faults.

And the composition of utility capital spending, disclosed in rate filings —
the split between distribution hardening, vegetation management, automation and
everything else. That is where the intention becomes visible before the outcome
does.

State utility commission dockets are the underused source here. Rate cases are
public proceedings in which a utility must justify proposed spending,
intervenors contest it, and the commission issues a written decision. The
documents contain far more operational detail about a specific network than
anything a utility publishes voluntarily, and they are free to read.

The general observation is that a system described as on the verge of collapse
is a system with published performance metrics, reported annually, by every
operator, in a standardized format. Whatever is happening to it is visible
without anyone's briefing.


The bill, not the debate

The average American customer lost about eleven hours of power in 2024, and
roughly nine of those hours came from three hurricanes hitting poles and wires.
Generation adequacy is a real and separate question with its own published
assessments. When a technology is described as saving the grid, do you know
which of the two failure modes it addresses?Connor Hill reads every reply.


Sources checked: U.S. Energy Information Administration — hurricanes in 2024
led to the most hours without power in a decade
<[link removed]> · U.S. Energy
Information Administration — Annual Electric Power Industry Report, Form
EIA-861 reliability data <[link removed]> · North
American Electric Reliability Corporation — Long-Term Reliability Assessment
<[link removed]> · North American Electric
Reliability Corporation — seasonal reliability assessments
<[link removed]> ·
Lawrence Berkeley National Laboratory — electricity reliability trends and
interruption cost estimation <[link removed]> · U.S.
Department of Energy — grid resilience and distribution system investment
programs <[link removed]>


Connor Hill · InsightfulWord





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