Introduction

There are about ten large "buckets" of oil that empty themselves daily into global storage tanks and then make their way to various ports of call. Counting crude and other petroleum liquids, the U.S. has the biggest bucket, pumping nearly 22 mm BOPD, followed by Saudi Arabia and Russia. After the top three, the daily buckets get smaller rapidly.

For the last couple of years, the cartel known as OPEC+ has been voluntarily withholding about 5.86 mm BOPD from the market with the goal of sustaining oil prices in the $80 for Brent per bbl range. That effort has been fairly successful, with Brent prices only rarely dropping below that level since early 2021. Wars here and there, the ups and downs of the economy, and political intervention have had relatively little impact on pricing. Oil, being a globally fungible commodity, is priced by traders according to their expectations of fulfilling contracts.

We believe that a tipping point is near (we may already have passed it), for U.S. shale liquids production, and this has broad implications for crude oil prices (CL1:COM), E&P companies, and oilfield service-OSF cohorts we spend most of our time discussing. We are not including an outlook for gas in this piece, as there are different drivers that will be discussed in a future article.

Doing more with less

While OPEC+ has been holding back barrels, U.S. producers have contrarily surged production to about 13.2 mm BOPD as a combination of new drilling, enhanced technology, and bringing forward top tier-most productive, locations. Since early 2022 the growth in oil output has been largely from technology enhancements-longer laterals, more stages, increased frac intensity, and improved AI-led, understanding of optimal landing zones over prior years. A propensity for Drilled but Uncompleted-DUC, wells to be completed and TIL'd through 2023 was also a factor in growth in the supply last year. Since the start of 2024 that trend has reversed and operators are adding DUC's into inventory.

In a departure from past cycles, this surge in output, particularly since Q-3, of 2022, has been despite a decline in the rig and frac spread count. In December 2022, the rig count stood at 784, and frac spreads in the field numbered 300. As of June, 7th 2024, these counts stand at 594 and 247 respectively.

So let's give the industry a big, heartfelt "attaboy," for working miracles the last few years! That done, we need to point out-we could be cresting a wave.

All good things...

The reality with which we are now faced is that the U.S. bucket is on the verge of beginning a decline, from it is doubtful will be reversed. For just the Permian alone to claw back the ~50K BOPD that's been lost since June 2023, another 35 rigs would need to go back to work.

Just so we are all on the same page, let's be sure everybody understands what "Legacy Decline" is. Shale wells have an initial surge, called the IP-30. This is maintained for a short time and then a rapid decline rate is exhibited. After one-year of production, a shale well has lost ~50% of its initial rate. By two years, over 90% of that initial rate is gone. So the legacy decline is the result of the age of the well inventory. New drilling and technology has outpaced this aspect until recently, but "the times they are a changin."

Why is this unlikely?

M&A has consolidated the number of drillers actively engaged in producing oil. As footprints are merged and production strategies rethought, the usual outcome is for operations teams to find a way to achieve targets with fewer rigs and frac spreads. In the last couple of years, several million acres have been consolidated in this manner. I don't think it is merely a coincidence that activity levels have declined as large acreage blocks have been merged across the Permian, Eagle Ford, and Bakken plays.

Companies have determined to maintain production flat or hold growth to low single digit increases in favor of allocating cash flow to shareholder returns and debt reduction. RBN Energy notes in a blog post recently that this trend is well enough established that capex has actually been cut across the industry this year.

A key clue is that U.S. E&Ps have put the brakes on capital spending increases in 2024, guiding to a 7% reduction in their investment budgets this year. Producers are sticking to maintenance-level capital budgets to prioritize free cash flow generation to fund shareholder returns and debt repayment. This strategy also slows the depletion of the remaining inventory of Tier 1 acreage that provides the most profitable development and production.

To put the icing on the cake, replacement rates and recycle ratios have been plunging since 2021. We will skip discussion of Tier I acreage in this piece. It's a complicated topic that deserves its own article.

When you add the recent high utilization of top-tier drilling (Super Spec rigs), and fracking assets-Tier IV DGB pumps and electrics, you don't have a scenario where the industry can scale up easily. Personnel to staff re-mobilizations could be an issue as well.

The good news

The industry has become so efficient that prices above $80 for WTI aren't necessary for the industry to maintain its production and capital return programs. Deloitte noted the relative strength of the upstream industry in their 2024 outlook-

This strength of the industry will likely enable it to finance both investments and dividends, and thus support its disciplined capital program and shareholder-focused strategy.

In that light, we think the sell-off in energy equities that's taken place over the last several months is over done. Many of the merged and unmerged shale operators are trading at attractive valuations and should be of interest to investors searching for growth and income.

One company in particular that's drawn our eye recently is EOG Resources, (EOG). The company is growing production organically, eschewing the big capital outlays M&A activity involves. EOG is a multi-basin operator, but has core areas in some of the best Delaware and Eagle Ford plays. It also has some international exposure through offshore blocks in Trinidad-Tobago. We think there is a solid case for the company rising toward the $140's, as per analyst forecasts.

If you don't find individual companies attractive, but want exposure to the sector, you may find the SPDR® S&P Oil & Gas Exploration & Production ETF (XOP), and United States Oil Fund, LP ETF (USO) ETFs the way to go. The XOP is composed mostly of beaten down shale players, stocks of which should rally if the scenario I've laid out does come to pass. At the same time, the USO ETF, which holds futures contracts for the commodity, is well off its highs and should benefit from the same set of circumstances.

Risks to the thesis

The key risk is that OPEC+ abandons their restraint and leaks barrels on to the market. That is an outlier given their recent extension of supply cuts into 2025, but you can never say never.

Secondarily, the Biden administration could release more oil from the SPR to drive down prices. This is also an outlier, but can't be discounted in any sudden rise in gasoline prices.

Your takeaway

What all of this means for the liquids focused E&P and OFS sectors is that the current downdraft should be coming to a halt soon. I am convinced that a demonstrable decline in liquids production, which I view as being unavoidable, will send a buy signal to the market, and help prices for shale E&P's and OFS companies regain some lost ground.

Nor will adding 100 rigs to the market overnight - it can't be done - change this dynamic. If we are losing 420K BOP per day in the Permian, that's a 153 mm barrel shortfall on an annual basis, and it can't be made up with a snap of the fingers.

I don't have a crystal ball and can't pinpoint a time when people will take their hats off and exclaim-"Dude, where's my oil." That said, I don't believe, based on what I've laid out in this piece, that it is too far off. My view is that if this scenario plays out, it will be very supportive for WTI in the $80's, and perhaps higher temporarily.