It’s a scary outcome for oilfield workers for obvious reasons. People in this sector have to decide whether to continue to build their career here or pivot to something adjacent or even something entirely new.

While I’m not in a position to offer general counsel, what I can do is paint a picture of the trends we should expect in future oilfield employment.

And one of the best examples we can point to is what’s happened over the past 150 years or so in agriculture.

Agriculture has spent decades doing something that sounds like a contradiction: producing more than ever while employing a fraction of the workers it once did.

We won’t trace the full 150-year arc here. The stretch since World War II is enough to see the pattern clearly.

That pattern shines a light on what’s happening in the oilfield today. A shrinking workforce, it turns out, can sit right alongside record production for long windows of time.

And the agricultural record tells us why that happens, and what tends to come next. In this way, agriculture offers a useful glimpse into the longer-term future of oilfield employment.

Let’s dive in.

US agricultural output has soared while headcount has plummeted

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But US rig counts aren’t budging.

And while the divergence is notable given the acute focus on the Strait of Hormuz, this breakdown between oil prices and rig counts is frustratingly common.

I did a big forecasting project in the summer of 2025 that produced multiyear outlooks.

I embraced Occam’s razor, using the simplest framework with the fewest assumptions to create a view of the future.

A super simple model is that today’s oil prices predict tomorrow’s rig count.

That didn’t work.

Okay, maybe the direction of travel of today’s oil prices predict the direction of travel of tomorrow’s rig count.

That also didn’t work.

It’s not that these assumptions are wrong. They’re just not always right. And they’re not right often enough that it quickly breaks down a forward-looking model.

Here let’s take a look at the historical data to see the frustrating ways that oil prices fail to tell us about what happens in rig counts.

And this isn’t just commiseration. It’ll give us some food for thought as we approach 2027 planning season.

Let’s dive in.

There is no magic WTI level at which rig counts climb or fall

As we see in the chart below, rig counts can climb when WTI is “low”, and they can fall when WTI is “high”.

The chart shows us the history of total US rig count versus WTI going back to 2014. The green shaded area is rig count and maps to the left axis. The orange line is WTI price and maps to the right axis.

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But is the optimism warranted? Or is it just the oil & gas industry trying to fight back against momentum around renewable energy?

In my recent presentations at conferences and corporate events, I have leaned into the divergence between the market realities around oil and gas, respectively, here in the US.

Oil is facing real questions around just how much more demand will materialize globally, and what the economics will look like as we approach this apex.

Gas is facing equal uncertainty, but almost all to the upside.

There are countless pathways where gas may play a larger role in our energy future. Even if it only grows at its rate from the past decade, gas producers and their service partners have a bright future ahead.

But “a bright future” is hand-waving.

So I built a data-driven, forward-looking model and used it to generate three views of US natural gas production out to 2040: a conservative case, a steady case, and an aggressive case.

The spread between them is wide.

Even the most conservative scenario adds nearly 30 Bcfpd of new production over the next 15 years. The aggressive case more than doubles that.

The variability across these scenarios is in what’s driving the growth.

And that distinction has real consequences for how producers and their service partners should position.

Let’s dive in.

Before we jump into future scenarios, let’s revisit our wild ride to this point

The chart below shows US natural gas production going back to 1997.

Those are the blue bars that map to the left axis, in units of billion cubic feet per day (Bcfpd).

The orange circles are the year-over-year (YoY) change in production, and map to the right axis.

Just one glance at this chart reveals two entirely different stories in the history of US natural gas production.

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And now everyone is trying to understand how exactly oil markets are going to change.

I argue the causation goes the other direction.

UAE is leaving OPEC because oil markets are already changing.

This is not the first high-profile departure from OPEC.

Back in 2019, Qatar announced it was leaving OPEC. But we didn’t have the same speculation about the organization’s future.

Seven years later, the consensus around oil’s long-term trajectory has sharpened, and this clarity explains UAE’s timing.

In this post, we’ll explore oil and gas production levels across the remaining OPEC members, plus Qatar and UAE.

We’ll see a variation of the liquids vs gas split that is defining capital flows and future outlooks across many of the world’s most prolific producing regions.

It’s a fascinating story, and the importance is completely separate from any speculation around OPEC’s future viability.

Let’s dive in.

UAE is the fourth-largest oil producer in OPEC

The chart below shows 2024 oil production in thousands of barrels of day for each of the remaining countries in OPEC, plus Qatar and UAE.

I highlighted the bars for Qatar and UAE, because we already start to see the stark differences in the way they participate in oil & gas markets.

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The headlines suggest US crude exports are doing something dramatic in response to the Iran War.

The data says otherwise.

Yes, US crude exports have moved higher in the eight weeks since the Iran War began. The week of April 10, 2026, the US EIA reported exports at 5,225 thousand barrels per day (kbpd).

That’s high, but it’s the 14th week in which the US has crossed 5 million barrels per day (Mbpd). And the all-time record of 5,629 kbpd was set back in February 2023.

The US has been operating near these levels for years.

In this post, we’ll trace the history of US crude oil exports going back to 1991.

We’ll go from the pre-2016 era when the US exported almost nothing, through the staged growth that followed the lifting of the export ban, to where the system sits today.

And we’ll close by examining the infrastructure constraints that are preventing a radical departure from the recent past.

Let’s dive in.

The US exported very little crude before 2016

Let’s start by looking at US crude oil exports going back to 1991, which is where the US Energy Information Administration’s data set begins.

In the chart below, weekly exports are the lighter green line. The four-week average is the darker green line.

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I hosted a live working session this week called Reading the Market After 6 Weeks of War where we made sense of a turbulent, noisy market environment.

The goal was to help oil & gas professionals pull signal out of the noise that’s been coming at all of us since the Iran War began in late February.

Here’s how I worked through it in the session, and where it leaves my 2026 outlook.

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The largest oil supply disruption in history

Yes, it’s even bigger than the 1970s. And the numbers aren’t close.

The IEA reports 10.1 million barrels per day (Mbpd) of production lost in March. The US EIA expects 9.1 Mbpd to be shut in through April. Strait of Hormuz flows are down to roughly 4 Mbpd from around 20 Mbpd before the war.

For historical context: the 1973 Arab oil embargo and the 1979 Iranian revolution each took around 5 Mbpd off the market, or about 7% of global supply at the time. Today’s disruption is over twice that in absolute terms, and roughly 10% of current global supply.

One potential difference matters, though: duration.

The 1970s episodes dragged on for years. This one may not.

The Trump administration has shown a consistent preference for negotiation, and that posture may yield a resolution faster than history suggests.

On the other hand, Middle East infrastructure has been damaged. Even after a settlement, repair timelines and rebuilt shipper trust in the Strait will both take time.

What’s partially cushioning the blow

Three things are absorbing pressure that would otherwise be in prices.

First, we have alternative routes.

Saudi Arabia’s west-coast pipeline, the UAE’s Fujairah line, and the Iraq-Turkey pipeline are now collectively moving about 7 Mbpd, up from 4 Mbpd pre-war.

Second, inventory draws. OECD stocks gave up 85 Mb in March, worth roughly 3 Mbpd of average relief for the month.

Third, non-OPEC production continues to build, with Russia, Kazakhstan, and Guyana among the most visible contributors.

None of this fully offsets the outage, but it’s the difference between a painful market and a broken one.

The Signal vs. Noise Filter

This is one of the frameworks we use in Oil & Gas Market Mastery, introduced in Week 2. It’s the tool I rely on most in a moment like this one, when the volume of market commentary outstrips its value by an order of magnitude.

The point is to separate the inputs that actually move my outlook from the ones that just capture my attention.

I watch oil prices every day. But I don’t use daily swings to update my view of the back half of the year.

The structure of the market (things like trade flows, supply-demand balances, the curve, inventories) is what tells me how the next six months are likely to shape up.

What the futures curve and the IEA are telling us

Two data updates this week do most of the work.

The WTI futures curve is in steep backwardation. The front-month contract is over $90. By July it’s at $86, by September $80, and by the start of 2027 it’s back to $75, closing that year at $71, still above the $65 pre-war level.

The long end of the curve is the market’s best read on equilibrium. The fact that the front has been bid up aggressively above it is the market quantifying the current supply shortage without betting it lasts.

On the demand side, the IEA’s April Oil Market Report cut its 2026 global demand outlook hard.

A month ago they had demand growing a little over 600 thousand barrels per day (kbpd) in 2026 versus 2025. Now they have it falling nearly 100 kbpd, a 700 kbpd swing in a single month.

Two features of that revision matter more than the headline.

First, the month-over-month drop is concentrated in LPG, ethane, and naphtha, or in other words, petrochemical feedstock.

If petrochemical plants come back online faster than the IEA assumes, a material share of this demand loss could unwind quickly.

Second, geographically, the destruction is concentrated in the Middle East itself. Africa and Asia-Pacific are still growing.

That concentration, again, creates possibility on the upside if the region recovers faster than currently expected.

Three scenarios I’m tracking

This is how I’m holding the next six months in my head. It’s not a forecast so much as a set of paths with different implications for different parts of the industry.

Ceasefire holds. Flows resume mid-year. WTI pulls back toward $80. The curve flattens as the front rolls down to meet the equilibrium level. This is roughly what the current curve is pricing.

Prolonged disruption. The Strait stays restricted. WTI sustains near $90. Demand destruction accelerates as high prices bite consumption harder. The curve stays in backwardation longer than markets currently expect.

Escalation. No diplomatic solution. The US and Israel proceed with further strikes or other leverage plays. WTI moves toward $120. Everything about the planning you’re doing today gets re-examined.

The value of holding three scenarios rather than one forecast is that you can tell senior stakeholders where you sit, what would change your mind, and what you’d do differently in each case. That’s a very different conversation than “I think prices go to X.”

The three things I’d tell a leadership team this week

If I had to distill the whole picture into a two-minute brief for a CEO or board, it’s these three:

1. Volume and price are separate discussions. The largest volumetric supply loss in history is sitting alongside a futures curve that prices $75 WTI by January. The supply shock magnitude and sustained price levels are different variables.

2. Demand destruction is narrow and deep, not broad and wide. The weakness geographically is in the Middle East, and product-wise it’s in petrochemicals. That concentration creates unwind opportunity if the recovery is smoother than expected.

3. Infrastructure optionality is the quiet story. With the Strait reduced to around 4 Mbpd of flow, barrels and molecules that have alternative paths are structurally more valuable than they were eight weeks ago. That has implications for asset valuations, commercial contracts, and where capital gets deployed next.

Here’s roughly how I’d write that up in three sentences, suitable for an email to leadership:

That’s the output you can hand to leadership after the analysis is done.

The analysis alone doesn’t get us where we need to be. It’s the communication, and the drive for and/or support of business decision-making, that earns executive attention.

Oil & Gas Market Mastery — Cohort 2 starts April 23

The work above is what we do every Thursday evening in Oil & Gas Market Mastery, a 12-week program that helps oil and gas professionals build executive-level market fluency.

The goal is not for you to become an analyst. The goal is for you to sit in the next leadership meeting and be the person with a defensible view.

We move from reading market signals, to creating a defensible outlook, then to communicating with confidence. The program will teach you how to do all three.

The founding cohort of 20 professionals wrapped April 1. Several members are already referring peers into Cohort 2. Here’s what two of them said about what the program actually changed for them:

“One framework from the program helped me hypothesize what direction WTI prices could go by the end of the year, and this helped me in a discussion deciding what price to use in an evaluation we are working on.” — Vice President, Private Equity-Backed E&P

“Coupling earnings call insight with improved breakeven analysis has allowed me to better understand E&P cash flow, capex, and implications for the OFS sector, improving our ability to project target plans moving forward.” — Director of Sales, Oilfield Services Company

Cohort 2 details

• Dates: April 23 – July 9, 2026

• Format: Thursdays, 5–6pm US Central, live via Zoom (recorded and available if you can’t attend)

• Cap: 25 seats

• Cohort Only: $2,400, includes The Energy Boardroom during the cohort

• Complete Access: $2,800, includes a full year of Boardroom access after the cohort, and locks in the founding-member rate of $600/year for life

Enroll at krimmelsg.com/ogmm

Questions? Reply to this email or write me directly at jeff.krimmel@krimmelsg.com.

The next cohort is filling. If the thinking in this piece is the thinking you want to build, visit the link above.

The team wrote that conversations with the major OFS companies as Q1 earnings wrapped pointed to a materially better picture for 2027 and 2028. They noted low double-digit expected growth, a broad-based international recovery, and what they framed as a return to the upcycle that began in earnest in 2021.

In their view, 2025 and 2026 will look like an aberration in hindsight.

For OFS management teams, investors, and the broader supply chain, that’s welcome news after several quarters of contracting spend and challenged shale economics.

As I read the Melius note, I was reminded of a book I first read 20 years ago.

It was about how tangible economic wins coming on the back of acute disruptions are often accompanied by wider losses that are harder to recognize elsewhere.

It’s true that the prospects of oil producers and oilfield service companies have improved materially over the past few weeks.

But the economic loss in the rest of the economy is profound.

And we’re not just paying the price today. We’ll be paying it for a long time into the future.

Why the oilfield services outlook has brightened

There are several drivers of the improved oilfield services outlook:

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But while we see invocations of force majeure and calls for energy rationing in Asia Pacific, disruptions to daily life in North America are far less profound.

The Middle East conflict is shining a spotlight on how varied the economic dependence on oil supplies is from one region of the world to another.

We start this post looking at the 15 countries that are the largest net producers of oil, meaning the ones who produce the most oil relative to their own consumption levels.

Then we look at the inverse, the 15 countries whose oil consumption most exceeds their oil production.

These two views help us understand who lives on each extreme of the oil-dependence continuum.

We then look at how the world’s 8.3 billion people are distributed globally, and we compare with the distribution of the 7.0 billion people that live in net oil-consuming countries.

This comparison quickly shows us just how exposed Asia Pacific and Africa are to disruptions in oil flows.

Finally, I close with some thoughts about what this exposure means for energy investments in the years and decades ahead.

The pain of the ongoing disruption from the Iran War is driving deep reflection around the degree to which different countries want to rely on imported fossil fuels as they respond to growth in energy demand.

This post will help us understand the urgency of this calculus.

The US produces more oil than it consumes, but there are 11 countries whose production surpluses are even larger

The US is the world’s largest oil producer, generating 20 million barrels of crude oil and other petroleum liquids per day.

And with demand of 19 million barrels per day, the US is a net oil producer, with a daily surplus around 1 million barrels.

There are 11 countries whose production exceeds their consumption to a greater extent than happens in the US.

Below we’re looking at the 15 countries with the largest net production levels. The geography of the results isn’t a huge surprise.

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But how much higher can they really go?

I’ve been asked this question countless times by audiences at speaking events and by media members reporting on the conflict.

And it’s entirely understandable.

Oil lives at the center of the global economy. Acute price spikes can derail economic growth and send inflation soaring.

These episodes wreak havoc on the best laid fiscal and monetary policy plans.

So, structurally, how high can these prices really go?

The short and fair answer is, there’s really no upper bound. That’s exactly the quote I gave to The New York Post.

History does tell us a bit about how oil markets have responded to these kinds of dislocations.

Already, recent oil price moves are the most extreme we’ve seen outside the pandemic and the first Iraq War.

If markets respond with similar ferocity here, we could see prices between $120 and $140 in the next few weeks.

Let’s explore the historical trajectory of oil prices to better understand what may lie ahead.

US oil prices are far from their inflation-adjusted highs

The chart below shows both nominal and WTI prices going back to when the contract first started trading on the New York Mercantile Exchange in 1983.

Nominal prices are the as-reported prices at the time. Real prices are what we get after adjusting these nominal prices for inflation, recasting them all in 2026 US dollars. The light green line shows nominal prices. The dark green line shows real prices.

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Valero is an independent US refiner with a $65 billion market capitalization.

This year alone, Valero’s stock price is up 31%. For reference, the S&P 500 is flat.

I decided to create the chart below, showing that Valero’s stock is up nearly 50% since September 2024. The S&P 500 is up 21%, with Marathon and Phillips 66, two other massive independent refiners, on its heels at 20%.

Refining is very much having its day.

And oil producers are not sharing in the fun.

As oil prices have continued to drift downward over the past couple of years, the fortunes of refiners have been going in the opposite direction.

In this post we’ll explore the market dynamics that have emerged in the refining sector, and why these dynamics differ materially from what’s happening on the upstream production side.

From a distance, it’s easy to imagine oil & gas as one large industry exposed to commodity markets in the obvious ways.

We’ll soon see that different segments of the industry can experience vastly different realities at the same time.

And today, the refiners (and their shareholders) are the ones celebrating.

Shareholders are driving refining stocks ahead of their E&P cousins

The chart below shows us the monthly average performance of the S&P Oil & Gas Refining & Marketing Select Industry Index (the “Refiner Index”) and the S&P Oil & Gas Exploration & Production Select Industry Index (the “Producer Index”).

We made September 2024 the baseline, and are looking at the change in these indices since that point in time. The S&P 500 is included for reference.

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