Every energy headline this year pointed at the Middle East. Oil prices. The
Strait of Hormuz. Whether the deal would hold. While everyone watched the sand
over there, the real story was under the sand right here - near the Grand
Canyon.



<[link removed]>

August 20


 



Earth's biggest energy source: near Grand Canyon

Find Out More →
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Every energy headline this year pointed at the Middle East.

Oil prices. The Strait of Hormuz. Whether the deal would hold.

While everyone watched the sand over there, the real story was under the sand
right here - near the Grand Canyon.

A crew reached a resource the International Energy Agency says could meet
global electricity demand 140 times over.

They did it in 16 days.

The DOE had budgeted 64.

It can't be sanctioned, embargoed, or shut off by a foreign government.

It runs 24/7, with zero fuel costs.

Google signed a 15-year deal. Gates wrote a $100 million check.

On August 18th, the government hands it an advantage every other energy
source just lost.

One company sits at the dead center of it.

See the story the headlines missed >>
<[link removed]>

“The Buck Stops Here,”
Kelly Maguire
Behind the Markets
 

 





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Here’s the Ticker →
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THE HILL REPORT

The Resource Was Never the Constraint

Connor Hill · InsightfulWord · August 19, 2026

There is a figure that circulates whenever the earth's internal heat comes up
in conversation, and it is accurate: the International Energy Agency's
assessment concluded that geothermal resources are theoretically sufficient to
meet global electricity demand many times over. The number is real, the
arithmetic behind it is defensible, and it explains almost nothing about
whether geothermal energy will be built.

Technical potential and economic potential are different quantities, and the
distance between them is where every energy technology has ever lived or died.
Sunlight falling on the world's deserts exceeds human energy consumption by
orders of magnitude. Wind moving through the atmosphere does the same. The
question that determines what actually gets constructed is never how much
energy is present. It is what a unit of it costs to extract, and whether that
cost is falling.

For geothermal, the answer to both questions sits almost entirely in one line
item. Drilling has historically accounted for more than half of the capital
cost of a geothermal project. Not the turbines, not the transmission, not the
land. The hole.

That concentration is unusual and it is analytically convenient, because it
means the entire economics of the sector can be tracked through a single
measurable quantity: the cost of putting a well into hot rock at depth, and the
rate at which that cost declines as more wells are drilled. Everything else is
secondary.

The reason the sector has become interesting over the past three years is that
this number has moved, and moved quickly, for a reason that is not mysterious.
Two decades of shale development in the United States produced a workforce, a
supply chain and a body of directional drilling practice that transfers almost
directly to hot rock. The IEA's assessment put it plainly: as much as80 percent
of the investment required in a geothermal project involves capacity and skills
already common in the oil and gas industry.

That is a statement about who can do the work, and it is the most
consequential fact in the sector. A technology that requires a new industrial
base takes decades. A technology that can hire an existing one takes years.

What follows is why the drilling cost dominates, what a learning rate is and
how the reported ones should be read, where the permitting layer actually
binds, the operating characteristic that makes the output worth more per unit
than intermittent alternatives, and what evidence over the next two years would
show whether the cost curve is holding.

Why Drilling Is the Whole Cost Structure

A conventional geothermal plant is a heat engine with an unusual boiler. Hot
fluid comes up a well, gives up its energy to a working fluid, and is returned
underground through a second well. The surface equipment is ordinary industrial
hardware with well-understood costs.

The wells are not ordinary. Depth drives cost non-linearly, temperature
degrades the electronics in downhole measurement tools, and hard crystalline
rock destroys drill bits at rates that sedimentary formations do not. A well
that takes two months instead of two weeks costs roughly what the rig and crew
cost for those extra six weeks, and rig day rates are the dominant variable
expense.

The next-generation approach changes the geology problem rather than solving
it. Instead of searching for a naturally permeable hot reservoir — which
restricted conventional geothermal to a handful of volcanic regions —
engineered systems drill into hot impermeable rock and create the flow paths,
using the horizontal drilling and hydraulic stimulation techniques developed
for shale. This makes the resource available across a far wider geography and
makes drilling performance the only thing that matters.

It also means the sector's cost trajectory can be audited. A company drilling
a series of wells in the same formation produces a public record of how long
each took, and the trend in that record is the trend in the technology.


What a Learning Rate Actually Measures

A learning rate is the percentage by which unit cost falls for each doubling
of cumulative production. Solar photovoltaics have sustained roughly twenty
percent for decades, which is why the modules are now the cheapest part of a
solar plant.

Applied to geothermal drilling, the reported figures have been striking. One
developer's disclosed well costs fell from$9.4 million to $4.8 million across
successive campaigns, with drilling times dropping sharply between pilot and
production wells, and the implied learning rate running well above the
company's own planning assumption.


📊 Fresh Energy Signal

$9.4m → $4.8m

Disclosed per-well drilling cost across successive next-generation geothermal
campaigns in the western United States, against an internal target below $3
million. Drilling has historically represented more than half of total
geothermal capital cost. Sources: Information Technology and Innovation
Foundation, May 2026 assessment; International Energy Agency,The Future of
Geothermal Energy.


Support or oppose: should federal permitting treat geothermal the way it
treats oil and gas?

Supporters argue that the two use nearly identical equipment and disturb
comparable acreage, that geothermal has been held to a slower review process
for historical rather than environmental reasons, and that parity would remove
a distortion rather than create a subsidy. Opponents answer that faster review
on federal land reduces the window for tribal and local consultation, that
induced seismicity from stimulation is a genuine and site-specific concern, and
that speed granted to one technology tends to be claimed by others. Where
should the line sit?Hit reply — one line is enough.

Two cautions belong with any such figure. The first is that early learning is
always the fastest. The move from a first-of-a-kind well to a repeatable one
captures the largest available gains, and rates measured over a small number of
wells in a single formation do not automatically transfer to a different one.
The second is that a cost per well is not a cost per megawatt-hour. A cheaper
well that produces less flow is not progress.

The honest way to read the disclosures is as evidence that the practice is
transferring from shale as expected, not as proof that a particular cost target
will be reached. The published capital cost figures — on the order of seven
thousand dollars per kilowatt today, with developers targeting three — are the
number that eventually matters, and it is the one to check.


Where the Approvals Actually Sit

Cost is one constraint. Time is the other, and the IEA's assessment noted that
commissioning a new geothermal project has taken up to a decade, much of it
consumed by consenting rather than construction.

The reason is structural. Most of the accessible high-temperature resource in
the United States lies under federal land in the Great Basin and the interior
West, which places projects inside the National Environmental Policy Act review
process. Geothermal exploration has historically required a full environmental
assessment at multiple stages — leasing, exploration, drilling, and development
— where an oil and gas operator on adjacent acreage might proceed under a
categorical exclusion.


Context — heat is the larger half

Electricity generation is the visible use of geothermal energy and the smaller
one. Direct use — district heating, greenhouses, industrial process heat, and
ground-source heat pumps serving individual buildings — accounts for the
majority of geothermal energy actually consumed worldwide, and it works at
temperatures far below those required to spin a turbine. The IEA's assessment
identified roughly 320 terawatts of thermal potential in sedimentary aquifers
within three kilometres of the surface at temperatures above 90 degrees
Celsius. None of that requires hot dry rock, deep drilling, or a power plant.

That asymmetry has been narrowing. Federal land managers have moved to apply
categorical exclusions to geothermal resource confirmation activities on
limited acreage, and individual large projects have been approved under
streamlined review. The direction is consistent across administrations, which
is itself informative: permitting parity for geothermal has attracted unusually
little partisan resistance, because the constituency that dislikes drilling and
the constituency that dislikes renewables are not the same people.

The practical effect is that the binding constraint is migrating from consent
back to engineering and to grid connection — which is a better place for it to
be, but not the same as its removal.


The Number That Makes It Dispatchable

Nameplate capacity is the figure quoted in announcements and the least
informative one. What determines the value of a generating asset to a system
operator is how much of that capacity is available when required.

Geothermal's utilization rate exceeded 75 percent globally in 2023, against
under 30 percent for wind and under 15 percent for solar photovoltaics. The
output does not depend on weather, time of day, or season. It requires no fuel
and therefore has no fuel price exposure, no delivery logistics, and no
counterparty in a producing country.

This is why the interest from large electricity consumers with continuous
loads has been disproportionate to the sector's size. A data center operator
does not want energy on average. It wants power at three in the morning in
February, and the contracts that have been signed reflect that preference
rather than a judgment about the technology's elegance.

The corollary is less flattering to the sector's promoters. High utilization
raises the value of each installed kilowatt, which means the technology can
tolerate a higher capital cost than intermittent alternatives and still
compete. It does not mean the capital cost has stopped mattering. It means the
threshold is higher than a naïve comparison of installation costs would
suggest, and lower than the enthusiasm implies.


What Would Confirm the Curve

Three published series would settle, over the next twenty-four months, whether
the cost trajectory is real or an artifact of favorable early sites.

The first is well cost per unit of delivered flow, rather than per well,
disclosed across at least two distinct geological settings. A learning rate
demonstrated in one formation is a result about that formation until it is
repeated elsewhere.

The second is commissioned capacity actually delivering energy under contract,
as reported in federal generation statistics rather than in announcements.
Geothermal capacity in the United States has been roughly static for two
decades, and the series will show any genuine departure from that plateau
clearly and without interpretation.

The third is the price in signed offtake agreements, where these become
public. A contract price is the only number in the sector that reflects what a
counterparty was willing to pay after examining the engineering rather than the
press release, and it is the closest thing available to an independent verdict.

There is also a question nobody can answer yet, and it is worth naming rather
than papering over. Induced seismicity from hydraulic stimulation ended one
prominent European project and remains the most plausible route by which the
sector could lose public consent quickly. The monitoring protocols have
improved substantially. Whether they are sufficient at scale, in populated
areas, is genuinely unknown, and a single badly sited project could do more to
slow the industry than any cost curve could do to accelerate it.


The bill, not the debate

The interesting question about an energy technology is almost never how much
of the resource exists. It is which single line item dominates the cost, and
whether that line item is falling for a reason that can be verified. For
geothermal, that line item is a hole in the ground, and the record of how long
each one took to drill is public. If a technology is described to you as
abundant, do you know which cost it actually has to beat?Connor Hill reads
every reply.


Sources checked: International Energy Agency — The Future of Geothermal Energy
, executive summary
<[link removed]>
·International Energy Agency — Investment in next-generation geothermal is
surging. Policies are key to further growth
<[link removed]>
·Information Technology and Innovation Foundation — Advanced Geothermal Energy
Is Widely Available, Clean, and Maybe Cheap Enough to Make a Big Impact, May
2026
<[link removed]>
·U.S. Department of Energy, Geothermal Technologies Office — Enhanced
Geothermal Shot
<[link removed]> · Bureau of
Land Management — geothermal permitting and categorical exclusion actions
<[link removed]>
·U.S. Energy Information Administration — Electric Power Monthly, geothermal
capacity and generation <[link removed]>


Connor Hill · InsightfulWord





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