Families aren’t driving, planes aren’t flying, and plastics plants are shuttered. The coronavirus-driven collapse in the world’s consumption of oil has sent the price of West Texas Intermediate Crude (WTI) from $63 at the start of 2020 to $14 on April 29, hitting lows not seen since 1998. The devastating hit to the U.S. shale industry and its aftershocks will decisively reshape the market and guide the course of future prices. Indeed, for the past several years, it was the rise of America’s frackers that broke OPEC’s chokehold, catapulted the U.S. above the Russians and the Saudis to become the top producer in the world, and held prices at around half their level of the previous decade.
The destruction in demand has caused the swiftest, sharpest collapse in U.S. oil output in history. It is also likely to accelerate a structural decline that was already in the cards, but might have taken 10 years or more to play out. By 2025, predicts one veteran analyst, the industry will be 10% smaller and show minimal growth. In that tumultuous five-year window, a wave of bankruptcies and distress sales will push the number of players from around 60 publicly traded producers to between 10 and 15. The six largest are on track to shed 40% of their oilfield service workers by mid-2020, a loss of 140,000 jobs.
Those are the forecasts from Matt Portillo, managing director at Tudor Pickering Holt & Co., a Houston investment banking and research firm. The bleak outlook is underscored by the sudden drops in the stocks he covers: In the past five weeks, shares of big independent drillers EOG, Pioneer Resources, and Devon Energy tumbled between 44% and 56%. For at least the past five years, says Portillo, the frackers—with a few exceptions—have funded their rapid growth by drilling generally unprofitable wells based on their all-in costs, and raising gushers of debt and equity on Wall Street. Investors were already souring on shale, but now that revenues are cratering, the markets will provide virtually no new funding.
Hence, Portillo foresees an entirely new industry emerging from the crisis. “For the past five years, this has been an unhealthy business,” he says. “It’s been all about more capital coming in and less free cash flow coming out.” For Portillo, the shale producers that survive will be the more prudent players that maximize returns over growth—the antithesis of the old buccaneers of the basins.
The retreat in shale signals danger that in the future, oil prices could surge back to the $80 to $120 level that prevailed before the industry’s rise challenged OPEC. So let’s examine how the frackers revolutionized the market, the forces that will curtail their output, and what their waning power is likely to mean for the future of the world’s most traded commodity.
The rise of shale
Fracking produces oil using entirely different technology from the traditional methods that for decades generated nearly all of the world’s supply. In conventional onshore and offshore wells, companies drill straight down, often hundreds of feet, to tap into subterranean pools. By contrast, fracking is more like coal or copper mining. Fracking rigs drill horizontally through a mile or more of shale rock holding oil sandwiched between the layers. The industry’s name is short for “hydraulic fracturing,” the technique that uses water, sand, and chemicals, pumped in at high pressure, to shatter the shale and release the oil and natural gas.
Frackers can sink wells, and reach peak production, much faster than standard onshore projects are able to. The typical shale rig drains 70% of the oil from the rock it’s targeting in the first year, and output continues declining sharply thereafter. As a result, the frackers can rapidly ramp up when a shortage lifts prices, or throttle fast in a glut.
The shale revolution revived the rowdy wildcatting ethos of the early 20th century. The big three regions are the Permian, straddling West Texas and New Mexico; the Eagle Ford in South Texas; and the Bakken, bridging North Dakota into Montana. It wasn’t the oil majors that primarily drove the revolution but adventurous, upstart independents such as Devon, Chesapeake, EOG, Diamondback, and Pioneer. Tiny hamlets mushroomed into boomtowns. The population of Williston, the Bakken’s shale capital, swelled from 12,000 in 2007 to 30,000 in 2018 as acres of trailer parks sprouted in the prairie. In the best years, the average oilfield worker was pocketing around $100,000 a year, and a drilling engineer earned $235,000.
The shale patch was the Wild West reborn, featuring poker games with $1,000 buy-ins, boisterous strip clubs packed with roustabouts, and brawling in the muddy streets illuminated by columns of flaring gas. Teams of armed guards shielded fields of explosives in the Bakken Badlands. The pioneers of fracking counted among the oil patch’s most storied gamblers. The gallery includes Aubrey McClendon, the Chesapeake cofounder who hopped corporate jets to his mansion on billionaires’ row in Bermuda and built a lavish, 110-acre corporate campus. Then, after being indicted for bid-rigging, he drove straight into an embankment at high speed and died in a fiery crash in 2016.
Shale also bestowed new glory on fallen legends. Herbert Hunt, the oil magnate who declared bankruptcy after an alleged attempt to corner the world silver market collapsed in the early 1980s, staged an amazing comeback as an octogenarian fracker, selling a big part of his stake for $1.45 billion in 2013. Hunt’s timing was canny. The frontier spirit captivated most of the big operators; they often prized sinking more wells over generating cash and kept drilling as if the good times would only keep rolling.
How shale held prices in check
The shale explosion established guardrails that curbed OPEC’s power to drive stratospheric prices. From 2004 to around 2014, the Saudi-led cartel was in charge. Global oil consumption was growing briskly, and OPEC, aided by turmoil in Venezuela, Libya, and Iran that curbed their output, held its production flat. The extra barrels that refiners needed flowed from extremely high-cost, deepwater wells in such locales as the Russian Arctic and off Brazil’s Atlantic coast.
But those OPEC-driven prices backfired by luring U.S. stalwarts that deployed fracking to ultimately produce crude at much less than Russian Arctic drillers, say, that were compensating for OPEC’s long-running squeeze. The frackers’ quicksilver agility rocked the world market. At the start of 2012, OPEC was generating 35.5 million barrels per day (bpd) versus the U.S. at 5.7 million, dwarfing stateside market share 40% to 6.4%. Fracking then exploded; even a price war that lasted 18 months in 2015 and 2016 only temporarily slowed the train. In fact, the shale crowd adjusted by lowering costs 50% in that interlude—and raising loads of new capital. From 2017 to 2019, frackers were growing at 15% to 20% a year, and expanding production by a staggering 1.1 million bpd annually.
All told, by the shale summit in November, the U.S. was producing 13.1 million bpd and capturing 13% of world sales. Shale accounted for 10 million of that number, and virtually all of the gains. By contrast, OPEC has shrunk to just over 28 million bpd, declining to 28%. Of the total rise in global consumption of 11 million barrels from 2012 thru 2019, the U.S. captured 7.3 million bpd, or two-thirds. OPEC’s output dropped by an almost identical number. “OPEC ceded share to the U.S.,” says Portillo. “Put simply, the U.S. forced everyone else to cut back. And even with the cutbacks, OPEC was unable to get to anything like the old $100-plus prices.”
The shale miracle was holding prices in a steady $55 to $65 range, handing the world’s drivers, airlines, and plastics producers a 50% discount from prices in the pre-fracking decade.
The new paradigm enabled the U.S. to supplant Saudi Arabia as the world’s largest producer. A report from the Dallas Fed from last May neatly describes the shale phenomenon. It noted that “shale has a shorter lead time between drilling and production relative to offshore and other traditional methods,” and that “shale production means there is a much larger amount of supply that can be called into action given a much smaller price increase than in the past.”
Three factors are now pummeling shale: a severe shortage in storage, a collapse in worldwide demand on a scale never before witnessed, and the retreat of the Wall Street backers that funded the boom—a pullback that will persist even when the market recovers. We’ll start with storage. The story that America’s depots are filling so fast that they’ll soon be brimming made headlines on April 21, the day before the expiration of the May futures contract. Producers and speculators that couldn’t find buyers for their crude were paying customers as much as $38 a barrel to take the liquid gold off their hands, a number driven by the escalating cost of storage.
Total warehousing capacity in the U.S. is 653 million barrels. By late April, 375 million or 58% of that space was full, and the glut is growing at 17 million barrels every day. That means America’s tanks will be 85% full by early June, the effective limit since facilities need a buffer for new supplies that move quickly in and out. America’s biggest depot, the famous Cushing facility in Oklahoma, will soon have no vacancies. It’s already 76% full, and its 20 million barrels in extra capacity will vanish in the next four to six weeks.
The confluence of a storage crunch and much longer-lasting drop in sales will force the frackers to shut down wells that produce a large part of their output. Portillo details how the interplay between the two factors will play out. Since the tanks at Cushing and all other depots will soon be full, the industry will have to produce even less oil than it can sell on the open market until the surplus recedes. It will take refiners a couple of quarters to work off the glut—the reason the crude depots are filling so fast in the previous link of the supply chain. “The refiners are selling at 25% their pace before the crisis,” says Portillo.
How fast will the frackers cut, first to counter the storage squeeze and then to meet the world’s diminished appetite? Those reductions are driven by what’s called the “variable” or “cash operating” cost of pumping oil from wells drilled months or years ago. Forget about the prices operators would need to recoup their big upfront investments. What determines which wells keep pumping is whether they can sell the output for more than the cash operating cost of squeezing the crude from the shale.
Portillo points out that rigs in fracking basins that produce a total of 1.1 million barrels per day operate either older shale wells or conventional, vertical wells. Those aging projects often yield a trickle of less than 25 barrels per day. “Their cash operating breakeven cost is between $15 and $30,” says Portillo. “They’re totally unprofitable at today’s prices.” In fact, the widely quoted WTI benchmark is an average that includes transportation costs, and is often far higher than the cash drillers are getting for each barrel at the “wellhead.” For example, in late April, the going price, picked up onsite, was $4.85 at the Kansas Common field, $4 in Colorado Southeastern, $13 in the Permian, and $13.50 in the Eagle Ford in South Texas.
Of the fields producing the remaining 9 million barrels per day, a significant portion is uneconomic at between $10 and $15.
Adding up the numbers, U.S. output should fall by a staggering 3 million barrels a day in Q2 and Q3 from their marks in January. Almost all of that hit will fall on shale, so that fracking production will drop from roughly 10 million in February to 7 million bpd by mid-May. All that 3 million reduction is needed to match the short-term fall in demand. By the end of the year, U.S. production will have fallen from 10 million to 8 million bdp. That’s a gigantic reduction of 20% since the start of 2020. “The market will work its magic,” says Portillo. “The 2 million decline caused by lack of investment in drilling new wells will start to stabilize the market.”
Shale doesn’t come back to the old highs
Portillo posits that around 300,000 of the 1.1 million barrels flowing from the older projects will never return. Many wells will be permanently damaged from the long shutdown, and others will simply be too expensive to reopen, given their paltry output. The remaining 800,000 wells will return to life slowly, and newer wells with lower operating costs will rebound faster. Portillo forecasts that by 2025, the frackers will be producing around 9 million bpd.
Still, that’s over 1 million below the summit reached late last year. From that point forward, output should expand at only around 300,000 barrels a year. And according to Portillo, this is the probable outlook even if prices surge back into the $60s, and get there pretty soon. “Fracking is widely profitable only at prices over $60,” he says. “And they could get there by 2022.” But in that favorable climate, the producers will eschew breakneck growth for profits. Portillo points out that in the Bakken, Eagle Ford, and regions except the Permian, the best fields are getting depleted fast, so that drilling new wells often won’t be profitable even at $60. “I predict that the drillers that survive will mainly sink new wells only to replace production that runs out on old ones,” he says. Instead, they’ll do what Wall Street will demand: Return free cash flow in dividends and buybacks, and mainly refrain from expansion.
That poses a big danger. Fracking’s great contribution is supplying the extra barrels the world consumes at relatively low cost. When global consumption starts growing again, shale is less likely to play that role, and OPEC could regain the whip hand—and once again drive prices over $100.
America’s fracking industry was headed for decline in any event. The outbreak steepened the slope—in part by sticking investors with even heavier losses and hardening their belief in the new paradigm: Shale can be profitable, but only if it barely grows.
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