President Trump’s “drill, baby, drill” agenda to increase daily U.S. oil production by 3 MMbbl to 16.1 MMbbl/d before the end of his second term has been met with much skepticism.
But in just the first two and a half years of his first term in 2017-2021, daily production increased by 3.7 MMbbl to 12.9 MMbbl/d, peaking in November 2019.
Who knows what might have been possible if the pandemic had not led to a collapse in demand—and thus, supply.
While Trump 45 was successful at significantly increasing production, a new consensus seems to be emerging that crude production is peaking—or worse, headed for an outright collapse—during Trump 47.
And key industry insiders have that can be construed as questioning how much U.S. shale oil producers have left in the tank.
A way of summing up the new consensus is that shale producers have already exploited all the easiest targets. As the targets get harder, it takes higher crude prices than we have now to make production possible.
Calling for a peak in oil production has been a national pastime for decades. My colleagues and I always pushed back against it, and we’ve always been right.
We’re going to push back again now.
EUR and IPs
Let’s look specifically at the Permian Basin, which is the focus of the current peak-production narrative.
Legacy lost production from 23,294 wells completed since Trump 45 left office has quadrupled lost volumes from total existing wells to 428,100 bbl/d in January 2025.
In January 2016, lost volumes from existing wells totaled only 104,646 bbl/d.
The U.S. Energy Information Administration (EIA) published decline curves for wells in the Permian Basin from 2019 to 2021. It has not updated the data since then, and no update is currently scheduled.
The next-best metric to assess wells’ estimated ultimate recovery (EUR) is one-year decline curves.
They are much better than 30-day initial production (IP) curves because operators can let pressure build prior to releasing the choke, thereby creating a gusher at abnormally high rates.
In 2016, the best independent analysis suggested that EUR for the top five Permian operators in the Spraberry, Bone Springs and Wolfcamp produced 265,000 bbl over their lifetime.
About 400 completions were needed to offset lost legacy production—or roughly 5% of 8,167 completions that year.
In 2024, the International Energy Agency (IEA) reported that one-year decline curves were 448,000 bbl, which peaked last year on an annual basis.
Again, operators need to replace four times more lost legacy production than in 2016, but that equates to only 1,000 completions—not four times 400 to hit 1,600 completions—because of wells’ higher EUR.
And while this is roughly 19% of 5,700 completions needed last year, the percentage is higher than it was in Trump 45’s first year in office only because the numerator—overall well completions—is much lower.
More technology
This is all very complicated, so let me be simple and clear: The industry is getting better at this, so more targets are easy targets.
Yes, a longtime peakist’s recent report suggests EUR has fallen back to the 2016 level—265,000 bbl/well.
Yet, the EIA’s findings on one-year year IP rates suggest that they are much higher.
Moreover, other credible research suggests that the Permian’s EUR was higher on average than our estimate of 428,000 bbl/well this year.
While EUR may have peaked in parts of the Permian Basin, advances in technology could maintain or boost them.
Right now, Chevron is working on lowering costs by completing three wells simultaneously, known in the oil field as a “trimul-frac.”
And Exxon Mobil projects that it will lift Permian EUR 15% with proppant made from refinery coke instead of sand.
Even the pessimistic EIA suggested in a recent report that new technology and pipeline construction are driving growth in the Permian.
The gas-to-oil ratio (GOR) has also been cited as a detriment to increased crude oil production.
While it has risen 29% in the Permian, operators in other basins have seen much higher increases.
A rising GOR can potentially lower oil production, but it's not a simple, direct relationship.
The Permian has developed infrastructure—pipelines and processing plants—to compensate for a higher GOR by making a virtue of it, sending Y-grade liquids (NGL) to the coast.
Since Trump 45, Permian operators have consolidated considerably. According to the Texas Railroad Commission, the top 32 operators in 2016 produced 59% of Texas oil, not including condensate. In 2024, it was 68%.
In 2016, the top five producers alone accounted for 34% of total oil output. By 2024, after significant M&A, the top five now account for two-thirds.
EOG and the Utica
Let’s focus on EOG Resources for a moment, as the current peak shale narrative has been accelerated recently by comments by its COO Jeff Leitzell.
First, EOG's share of Texas crude oil production has dropped from 13% to 4% as rivals have consolidated.
Its core area of operation has been the Eagle Ford and not the Permian.
Secondly, EOG looks for organic growth and usually does not tap into the M&A market. The historical exception was when it acquired Yates Petroleum, a private company with significant Permian acreage, in 2016.
Since then, the majors have bought Permian assets and overtaken EOG as Texas' leading oil producer.
Diamondback Energy has been the only independent to significantly acquire Permian acreage and production.
In May, EOG announced it will pay $5.6 billion for 675,000 acres in the volatile oil window in the Utica shale, a play geologically similar to its familiar ground in the Eagle Ford.
So EOG isn’t giving up on shale as Leitzell’s statements have been interpreted to imply.
This very savvy E&P went shopping for oil-prone acreage outside of the Permian at a lower price—a far cry from claiming “peak shale.”
Indeed, the company calls its new acreage in the Utica the “little Permian.”
Technology leaders like EOG understand that while the consensus is worrying about the industry running out of easy targets, those very same easy targets were called hard targets just a few years ago.
EOG’s Utica acreage is just that. Why couldn’t Chesapeake Energy (now Expand Energy), the Encino Utica property’s one-time owner, do anything with it before?
Less red tape, lower cost
Production dynamics aside, another factor is economics.
Oil prices are a big determinant of profitability, which itself is a key determinant of production: Higher is better.
But high prices have a dark side. They suppress demand.
Another big determinant of profitability is cost. If the cost of production falls, then profitability can be maintained or even increase despite lower oil prices—and, better still, there’s no hit to demand.
Indeed, at lower prices there will be an increment to demand. If producers hold their margins and move more units, they are more profitable.
The Biden administration erected regulatory barriers on oil and gas that were meant to raise production costs, doing everything in its power to push prices higher to get traction for its green energy agenda.
WTI averaged $80/bbl under Biden.
To be sure, he had to reverse course after the invasion of Ukraine when oil prices got too high too fast. He drained more than 250 MMbbl of oil from the U.S. Strategic Petroleum Reserve. That helped consumers, but did nothing to lower the industry’s cost function.
Trump’s agenda is to reduce producer costs by reducing their regulatory burdens. The strategy appears to be working: WTI is averaging only $68/bbl this year.
Despite this lower price, production is averaging 200,000 bbl/d more than the comparable period last year.
There are other economic factors at work.
Some observers say high interest rates will make capital scarcer to operators, forcing them to reduce capex and forgo future production.
Trump 47 started his term with a federal funds rate of between 4.25% and 4.5%.
But today, many oil and gas companies finance a significant portion of their operations using free cash flow generated from existing activities.
Industry debt has fallen 34% since 2019. An interest rate cut will help on the margin, but the industry isn’t dependent on funding its operations with a near-zero funds rate.
Tariffs
Trump 47’s energy deregulation policies will yield significant cost reductions over the coming year.
But at this moment, many operators are dealing with rising steel prices due to Trump’s tariffs.
That at least works in the direction of offsetting the cost benefits of deregulation.
In the Permian, several companies have cited rising costs at the local level, but some CEOs think the tariff impact will be modest.
Countries such as China retaliating against U.S. tariffs might raise duties on U.S. oil and petroleum products, but so far, there hasn’t been a noticeable slowdown in U.S. energy exports.
For all our optimism about the ability to grow U.S. production, you’d think we’d be calling for lower oil prices.
But we are sticking with our call made at the beginning of the year, for a range between $60 and $80 on the Brent benchmark.
That has served us remarkably well so far in a somewhat volatile year.
That is in part because the deregulation initiatives we are so enamored of will operate not only to increase supply, but also to increase demand.
The One Big Beautiful Bill ushered in one of the biggest tax cuts in history—much of it retroactive as it applies right now in the 2025 tax year—and abolished the electric vehicle subsidy.
Meanwhile, Trump’s tariffs are likely to be demolished by the Supreme Court within a short number of months.
The combination should result in economic growth that will support strong oil demand growth.
There will be plenty of supply. And there will be plenty of demand.
Bottom line
There’s a new narrative of peak shale, even in the Permian. The story goes that the easy targets have all been drilled, and the harder targets aren’t profitable at today’s prices.
But today’s easy targets were hard targets just a few years ago.
Evidence from decline curves shows that shale plays are as productive as ever.
The skeptics, as always, are blind to the roles of operating experience and technology improvements in getting more oil out of rocks profitably.
Much has been made of EOG’s worries about shale. The operator’s concerns arise from its experience in the Eagle Ford, yet that is being extrapolated to the premier Permian shale play.
EOG itself is investing heavily in other shale plays, including the formerly difficult Utica, which it now calls a “little Permian”—showing that business and technology dynamism can always reinvigorate the drilling game.
Trump’s deregulatory policies are lowering costs and increasing demand at the same time.
We reiterate our forecast for a price range of $60 to $80 Brent.
Michael Warren is the energy strategist for Trend Macrolytics. Previously, he was a senior vice president for Hart Energy, running the upstream research group. He can be reached at mike@trendmacro.com