Wall Street Is Finally Going to Make Money Off the Permian
Analysis by Javier Blas | Bloomberg April 24, 2023
The huge electronic display reads like a call to arms: “M.O.G.A. Make Oil Great Again.” The pixels soon become five drilling rigs, crude gushing from the top as if they were bottles of champagne.
It stands across the street from the Petroleum Club of Midland, the Texas town that’s the capital of the Permian oil basin. Midland is all about oil and money: Its main thoroughfare (where the club and sign are located) is called Wall Street; George H. W. Bush started his oil business here in the 1950s before entering politics; the main tourist attraction is a petroleum museum. The landscape is dotted with oil drilling pads and pumpjacks that surface the hydrocarbons that power the American economy.
Oil is a 100-year-old business here. And, if the pixels are to be believed, it will carry on. The screen goes on to declare, “It’s a great day to drill an oil well.”
However, in the table-flat, sage-scented desert that’s the Permian, drilling has slowed from the heyday of the US shale revolution. It’s the same elsewhere in the American oil patch. As of last week, 590 rigs were drilling in the US, down from the most recent peak of 627 rigs set in November. That was already significantly lower than the 888 recorded in 2018 and the high point before that — 1,609 rigs in 2014.
Driving across the Permian, which stretches from West Texas into southeast New Mexico, signs of the slowdown are everywhere. In one place, half-a-dozen unused rigs are stacked up in a yard waiting for better days; in another, a once-bustling man camp is half empty. If it’s a great day to drill an oil well, no one seems to be in a hurry to get the work done.
The go-slow is a business reality. Over the last decade, the US shale industry had become a byword for capital destruction. Shale investors recovered about 50 cents for each dollar they invested during the 2010-2020 period. After riding out the pandemic, the industry is under increasing pressure from impatient stakeholders on Wall Street — the actual embodiment of the financial system, not Midland’s mock version. Shale pioneers once put growth over profit, burning billions of dollars in the process; today, they are focused making money for their shareholders.
The annual growth rate of US shale is about half of what it used to be when oil prices were at a comparative level as today. It’s still growing but far from the wild rates of the past. The monster that tore out of Texas to change the world has become a tamed animal.
The slowdown marks the beginning of the end of the greatest American oil boom. “You see the plateau on the horizon,” Ryan Lance, chief executive officer of ConocoPhillips, told an industry conference recently. “Peak Permian will happen in the next five to six years,” said Scott Sheffield, the boss at Pioneer Natural Resources, one of the biggest companies in Midland.
It’s a humbling moment. For a few years, the technological breakthroughs in horizontal drilling and fracking made it look as though the American oil gusher would be ever more bountiful. Shale redrew the world’s energy map and, as a consequence, its politics; many — wrongly— assumed that the new boundaries were permanent.
What happens next matters well beyond the windswept streets of Midland. For nearly two decades, shale was ruinous for its shareholders, but it was hugely beneficial for the rest of America. It kept oil prices lower and provided jobs and investment. Just as significantly, shale gave the White House a powerful geopolitical lever to face oil-rich foes like Iran and Russia. Let me say this: The shale boom was the most profitable example of capital destruction the energy industry has ever seen. Investors lost, but the US and most of its allies won.
Over the next few years, the tables will be turned: Wall Street is going to profit at the expense of Washington and Main Street. The consequences are likely to be higher oil prices — and inflation — and a weakened hand in energy politics. Earlier this month, Saudi Arabia and Russia led a group of OPEC+ nations in cutting production. In the past, the oil cartel would have been afraid about fueling the growth of shale, and ultimately losing market share. Today, it’s aiming to grab the steering wheel of the oil market again, at little cost. Texas — and the US — will have to take a back seat.
How did this happen? Let’s start with how the industry hacked geology.
The Art of the FrackShale formations look like a tiramisu, with thin layers of productive rock sandwiched between non-productive ones. Over the past couple of decades, US wildcatters learned to drill vertical wells several miles deep into the tiramisu, and then turn the bit around 90 degrees to proceed horizontally — often as far as 15,000 feet, or 4,500 meters. Those L-shaped wells reached deep into the productive stratum and then began the fracking — water, sand and chemicals were blasted deep underground to free oil from the rock.
The combination of horizontal drilling and fracking had staggering results for American oil. US production had fallen steadily since the mid-1980s and almost everyone in the industry assumed that the decline was inexorable. In 2008, the country’s total production, including crude and other liquids, had fallen to 6.8 million barrels a day, the lowest since the 1950s.
Instead of a sunset, however, a new sunrise arrived. Thanks to the new shale techniques, oil fields long thought in decline — like those in the Permian which had been pumped for about a century — enjoyed a second life. From 2008 to 2015, American petroleum output was just short of 12.8 million barrels a day. By 2019, just before the pandemic, it had surged to 17.1 million barrels a day, transforming the US into the world’s largest producer, ahead of Saudi Arabia and Russia. By last year, output reached a record high of 17.7 million barrels.
The first chapter of the revolution —let’s call it Shale 1.0 — was written by wildcatters like Harold Hamm, a friend of President Donald Trump, and the late Aubrey McClendon, who parlayed borrowed money into the billions. It lasted from 2008 to 2015 and was mainly located in the Bakken formation in North Dakota, and the Eagle Ford deposits in southern Texas. Hamm and McClendon proved shale was a tenable source of energy despite deep skepticism both inside and out the industry.
The technology, however, required difficult, nearly nonstop operations. After a few weeks of high production, output rates at the sites fell precipitously, all the oil squeezed out. The only solution was to drill even more wells — which meant money that had just been made had to reinvested immediately. Soon, shale companies were spending all of their profits, and then borrowing on top. At the time, shareholders didn’t care because the promise of growing output was staggeringly strong.
American oil production jumped so much that OPEC said enough was enough. In late 2014, Saudi Arabia and its allies launched a price war, flooding the market with their own petroleum. Prices fell from $100 a barrel to $50 in 2015, and less than $30 in early 2016. Shale companies — which needed the high prices to justify their cash-intensive operations — failed by the dozen. So much that — as one joke went — the only profession in demand in the oil patch was bankruptcy lawyers. At an industry conference in Houston in early 2016, then Saudi Arabia Oil Minister Ali al-Naimi, sent a blunt message to his US rivals: “Lower costs, borrow cash, or liquidate.”
To their credit — and Naimi’s chagrin — the drillers took his advice. The companies that survived became fitter, leaner and faster. This was Shale 2.0. Output boomed and overwhelmed the market. Even after Saudi Arabia roped Russia into an alliance — the OPEC+ group — it struggled to keep oil prices high. That was bad for both the cartel and Texas. From 2017 to 2019, West Texas Intermediate averaged less than $60 a barrel, compared to $95 from 2012 to 2014. The shale companies made money when prices were high; but as soon as they fell, particularly below $60 a barrel, shivers went through the patch. That’s because the original sin remained: the need to constantly drill new wells meant most profits still had to be reinvested.
More pressure piled up. Wall Street wanted the oil industry to make money; if not, they would take their investments elsewhere. Meanwhile, climate activists and green reformers wanted to force pension funds and other big institutional investors to divest their holdings in fossil fuels. Shale was unprofitable and dirty, wedged in from the right and the left. The money that bankrolled the energy revolution began to leave.
Shale needed major surgery. And at that moment, the pandemic arrived, crashing the oil market and making the transformation even more necessary and also, far more painful.
What emerged was Shale 3.0 — where we are now. Gone are the days of “drill, baby, drill” and huge annual production increases. Instead, dividends and share buybacks are the new norm. Goldman Sachs Group Inc. estimates that US publicly listed shale companies reinvested the equivalent of 120% of their operating cash flow into new wells in 2012. Ten years later, that rate plunged to 40%.
The shift from growth to profits has come at a cost. Despite $100-plus oil prices in 2022, total US oil production — including crude, condensates, and natural gas liquids — grew by just 1 million barrels a day, half the rate of 2018 when oil prices were much lower. Crude output — the segment of total oil production which is important — grew last year by about 600,000 barrels a day, compared to rates of more than a million in 2014, 2018 and 2019.
Everything suggests that the growth in crude production will slow further in 2023, perhaps to as little as 500,000 barrels a day. The increase is likely to be even smaller in 2024. Industry executives, traders and consultants offer diverging views about when total output will hit its apex, but that day is closer than many think: US production is likely to peak in the next three to five years, and certainly before the end of this decade.
Of the five major US shale basins, two are already past their prime: the Bakken, where most of the Shale 1.0 happened, and the Eagle Ford. The situation in North Dakota is emblematic of shale’s troubles. Oil production there crested at 1.5 million barrels in November 2019. Today, it’s struggling to maintain the 1 million barrel mark; few in the industry believe output will return to or surpass the level of four years ago.
Another key shale basin, the Anadarko-Woodford in Oklahoma, has probably peaked too. Still, two other basins are growing, including the Permian, which is by far the largest, accounting for more than half of US shale output, and the Denver-Julesburg, straddling Colorado and Wyoming. Beyond shale, US oil production is in decline, with output falling from Alaska to California to the Gulf of Mexico even as the major OPEC+ nations are pumping at historically high levels.
Shale Goes from Boom to Gloom. Driving north from downtown Midland, you will pass newly built swanky neighborhoods and one of the town’s three golf courses. But just after crossing the city limits, the oil rigs appear immediately. On one side of the highway, a water tower proclaims “Midland: feel the energy.” One of the L’s is shaped like an oil rig.
Shale companies are drilling so close to town that their horizontal sections would ultimately tap reservoirs under the McMansions. We are getting pretty close to where our CEO lives, quips one foreman, prompting general laughter.
For the industry, it isn’t a joke. The placement of new rigs is why shale production growth is slowing. The best drilling sites have already been tapped. New drilling is moving into more difficult or expensive sites, close to – or even within – the city limits of the Permian’s towns. In industry jargon, shale companies are moving from tier 1 locations into tier 2 and tier 3 areas.
Productivity has peaked for the first time since the shale revolution started more than a decade and a half ago. Engineering feats that once managed to squeeze out lots of oil aren’t as effective any more. These include what’s called multiple-bench drilling — where a company targets several of the tiramisu layers at the same time from a single well. Chevron Corp. told shareholders earlier this year it had revised its shale program to do more single-bench developments compared to 2022. “Our Permian growth would be a little lower in 2023,” said CEO Mike Wirth. Raoul LeBlanc, a veteran shale-watcher at the consultancy S&P Global Inc. says, “shale wells are now as good as they will ever get.”
In 2008, the average Permian well pumped about 7,000 barrels over its first year of life, according to data from Rystad Energy, an Oslo-based consultancy. Then, wells got better thanks to improved techniques, loads of cash to support experimentation and favorable geology. By 2016-17, the average rig pumped 17,000 barrels in its first year. Since then, however, productivity has flatlined, and early data for 2022 suggest it has declined even more. “With persistent capital discipline, less cash to play around with, and pressure to return capital to investors, there is an incentive to go full steam ahead with ‘factory mode,’ that is repeating what works, and less room for experimental designs,” says Alexandre Ramos-Peon, a Houston-based analyst at Rystad.
The industry is facing three further headwinds that explain why it can’t (and won’t) return to the growth rate of the past. One is the price of oil itself. The golden years of shale growth coincided with WTI trading close to, or above, $100 a barrel. Since then, prices haven’t been as high, notwithstanding a brief period in 2022 after Russia invaded Ukraine. Nowadays, WTI is struggling to hold the $80 a barrel in nominal terms. Adjusted for inflation, WTI will need to rise to more than $135 a barrel to have the same value as $100 in 2008.
The memory is still fresh and stinging from two recent OPEC price wars — the 2014 one directed against shale, the other between Saudi and Russia, where shale was collateral damage. The latter — just three years ago — saw WTI briefly trade below zero, plunging dozens of shale outfits into bankruptcy. The survivors now live cautiously — and with that comes lower spending.
Caution has another effect. In its early days, shale behaved like a dimmer, with output growth accelerating proportionally as oil prices were dialed up. That ability to respond quickly to the market was due to the speed at which shale wells could be developed: a few months compared to to the years or decades of Big Oil projects. Today, shale is as responsive as in the past. But there’s a difference. The dimmer appears to be capped at a certain level: No matter how high oil prices go above that level — say $100 a barrel — the industry will no longer add rigs to sop up market share. Rather, it will stay put and go into harvest mode with existing wells — that’s exactly what happened in 2022, much to the consternation of the White House, which urged shale companies to drill more.
The second headwind is costs. Activity levels in the oil path are nowhere near what they were in previous booms, but the price of everything is rising. The oil patch isn’t different from Main Street, which is also battling inflation. “We have WTI trading at $70 a barrel, but costs are as if it was well above $100,” says R.T. Dukes, an oil consultant turned CEO of a small oil driller. Drilling to offset the natural depletion of wells was easier in the early days, when the legacy production base in decline was relatively small. It’s now a gargantuan task — and it’s getting more and more challenging to sustain output.
The third factor is consolidation. As the shale industry matures, bigger companies are buying the smaller ones — and the net result is a decline in activity. When Ovintiv Inc., a medium-sized shale company, announced in April it would spend $4.3 billion acquiring the oil and gas assets of EnCap Investments, a private equity group, it said that the enlarged company will require fewer rigs. Within the Permian, Ovintiv and EnCap were running about 10 rigs in total before the merger; after the deal is completed, Ovintiv said it expected to use only half of them. The trend is likely to accelerate. Exxon Mobil Corp. has been unusually candid about wanting to buy smaller rivals in the Permian — Pioneer appears to be its obvious target, as the Wall Street Journal reported.
In its early days, the shale industry was made up of dozens of companies; by the end this decade’s M&A, there may be only 10 or so super-shale companies doing much of the drilling. That will further slow the sector. In 2020, ConocoPhillips bought shale company Concho Resources, which at that time was growing its production as fast as 30% per year. This month, Conoco said that its 10-year plan envisaged increasing shale production at about 7% per year. Wall Street’s Permian Windfall. What emerges from the M&A will be Shale 4.0. It will be dominated by larger but slower companies like Exxon and its archrival Chevron. The end of the oil production boom isn’t the end of the industry. It will just change personality: becoming more pliant to the profit motives of Wall Street. Indeed, less output growth means better returns for the stockholders of the shale companies. As tobacco proved years ago, reducing capital expenditures — thereby freeing more cash for shareholders — can be very profitable.
The end of the days of being wild are not the end of the days of influence and power. The shale industry may be domesticated, but it is still a force to reckon with. Last year, shale grew strongly enough to push overall US petroleum output to an all-time high. Even growing more slowly, shale will still be the biggest source of additional production around the world, ahead of non-OPEC nations like Canada, Brazil or Guyana, which have higher growth rates.
When I visited Midland, Houston and Dallas in March, the consensus was that peak US output would happen around 2026 or 2027. Even after that, total US oil production is likely to settle at a high plateau, remaining flat for a few years, rather than quickly drop, which is what happened after the previous peak in 1986.
While the industry will continue to thrive, what will a post-peak planet look like? Today, shale accounts for one in 10 barrels of oil pumped worldwide, almost matching the individual output levels of Saudi Arabia and Russia. Its swift development over 15 years helped extend US diplomatic clout and buoy its economy. At the same time, cheaper oil probably delayed the energy transition, making alternatives like electric cars less competitive.
The chronology, however, had its benefits: Cheaper oil gave the alternatives time to prepare. An abrupt transition amid high energy prices would have been traumatic without technologies to help ease us into a greener world. Tesla Inc. started production of its first car — the Roadster — in 2008, the year the boom began; in the period when shale shook the pillars of world oil prices, Elon Musk was able to build his EV empire.
Perhaps more significantly, shale transformed the natural gas market, reducing prices so much that gas pushed coal out of the American electricity production system, reducing carbon emissions sharply.
So shale bought us a bit of time. What comes next will largely depend on how quickly the world can move away from fossil fuels. If global oil demand starts to drop in the next few years — and certainly by around 2030 — US oil production past its prime would matter relatively little. The lower American output would coincide with lower global oil demand, one offsetting the other.
However, if the world keeps consuming more hydrocarbons, or, as I believe, if global petroleum demand settles at a high plateau rather than falling a cliff soon after peaking, then the weakened shale growth engine will have a profoundly negative effect. I’m afraid that, despite the rosy projections of a world moving into net-zero emissions, global oil demand is likely to surprise on the upside. The world will come to miss the wild days of the shale boom, when shareholders lost, but consumers won.
Although the article is based on oil (the Permian Basin being the prime subject), it is a good representation and projection for US future production from unconventional basins including the Haynesville/Bossier. The market for oil has a natural gas impact based on "associated gas" volumes. The future plateau and decline of the Permian and the Haynesville are related. This relationship to depletion of Tier One acreage and increasing production from Tiers Two and Three relates to a lesser extent to the Haynesville Play as it transitions form Haynesville to Bossier reserves. The Haynesville/Bossier only has two "benches".
This is looking long term as O&G CEOs, investors and mineral owners of significant acreage should be doing. For the most part, forget partisan arguments about energy policy. This is driven by resource depletion which is impacted by neither but will be prolonged by the demand for hydrocarbons. If Permian oil production plateaus in three to five years, regardless of how long that "plateau" may last, it will be time for those in decision making positions to decide how to maximize a liquidation and to avoid stranded assets.
As I mention periodically, the opinion and advice I give here (GHS) is no different than the advise that I provide for paying clients. No one managing those assets wishes to be caught with stranded reserves that could have been monetized but are now virtually worthless. Every time natural gas prices increase is an opportunity to monetize some portion of the total interest held. Every time that natural gas prices tank, it's a good time to hold. This cycle of price spikes is historic, it has gone on for decades. For those managing mineral assets, the question should be, "how many price cycles are left???" No one knows that and when it become obvious, it may be too late to liquidate a mineral asset. An incremental liquidation plan is a good strategy at this point.
Skip, a very interesting article and timely. I was talking today with a friend in Florida about O & G activity in Cass County. He asked about the Permian Basin and having read other articles like this, I summed it up as a disappearing field. Now, Cass County is still active with Rose City and Barrow-Shaver of Tyler drilling many wells. And, we have brine leases (lithium) playing out across the Smackover formation from East Cass County to Mt. Vernon. Is lithium the "new oil"? I can only say it is as early in its growth as was the 1900s discovery of oil.
Joe, I would say that the days of significant Permian increases in production are waning and the production plateau is in view. Still it will take some years before production decline sets in. Yes, I've noted the increased drilling in Cass County but I think it is a blip in time and the real value is in the possibility of major brine production and lithium demand. We will see how that develops. Of course, there is much research in battery technology and the possibility that lithium may be eventually replaced by something better.
The problem with lithium production is that not all waters (from which the lithium is extracted) are created equal. Cass County is in a sweet stop of the trend where lithium concentrations are sufficiently high to "mine" from the deep wells in that area. Similar to some areas along the Arkansas / Louisiana state line.
I am not a geochemical expert, but I believe the reason for these areas being good for these high concentrations of important minerals is the location of the reservoirs (Smackover being one of the major zones) with respect to the salt / evaporitic sections (Louann and Buckner) as well as deeper stratigraphic section (Paleozoic interval).
Thanks, Rock Man. I think we all look forward to how companies choose to pursue the Smackover brine in Cass County. Battery tech is evolving quickly and many research efforts are aimed at eliminating the scarce and expensive battery materials with lithium being top of that list.
As technology advances, the window may close quickly on minerals like lithium and cobalt.
What will be the "new" high tech mineral of choice?
very interesting, in-depth analysis.
thanks for posting, Skip
Glad you you found it interesting, Steve. I think it is wise to have a ten year or longer outlook when managing mineral rights. The cyclical nature of supply and demand will not play out forever. Price spikes and price crashes will continue to follow one upon the other until the age of hydrocarbon energy is no more. The decline will take decades but will cause stranded assets based upon "cost to produce". The most costly will go first and the last assets economic will be the lowest cost to produce. The slide will take many years but we all won't be there at the end. Many will reach economic obsolescence long before that end. Smart managers know when to liquidate.
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