Shale Industry Drills More Debt (Over $280 Billion) Than Profit (#GotBitcoin)
Since 2007, the oil and gas industry has lost $280 billion betting on the shale boom, which has been made possible by hydraulic fracturing (fracking) and Wall Street financing, and these companies are still borrowing heavily. Shale Industry Drills More Debt (Over $280 Billion) Than Profit (#GotBitcoin)
But even as the industry struggles to recoup costs — much less profits — by continuing to borrow and drill, the great promise of the shale revolution is also threatened by another specter: declining production at each well.
In this series, DeSmog’s Justin Mikulka and Sharon Kelly investigate the finances of the fracking industry and how falling fossil fuel output and questionable lending practices reminiscent of the mid-2000s housing bubble may be setting up another bubble, one with a bill that may ultimately be paid by American taxpayers and the planet.
Will The Fracking Revolution Peak Before Ever Making Money?
Perhaps the surest sign of desperation among shale firms is the issue of “frac hits” or “child wells,” an issue DeSmog flagged over a year ago. These companies are aware that if secondary or “child wells” are drilled too close together around the primary, or “parent well,” the fracking process can damage the nearby wells. And they also know that, as a result, these wells do not perform as well as those with greater spacing.
Nevertheless, they continue to do it.
Instead, wells are declining faster, meaning the output of the wells drops off very quickly and leads to lower overall well production — and more losses for the increasingly financially insolvent companies.
James West, a managing director at Investment bank Evercore ISI, assessed the situation for the Wall Street Journal. “We’re getting closer to peak production and we are reaching the peak of the general physics of these wells,” he said.
Physics, Geology, and Disappearing Sweet Spots
Perhaps the most important fact in the Wall Street Journal’s recent story was only mentioned once: “sweet spots [are] running out sooner than anticipated.”
Sweet spots are the areas of shale basins that have the best-performing wells. David Hughes, earth scientist and author of the 2019 report, “How Long Will The Shale Revolution Last: Technology versus Geology and the Lifecycle of Shale Plays,” has estimated that these sweet spots (also known as “Tier 1 acreage”) make up 15 to 20 percent of a shale basin (also known as a “play”).
In a recent online presentation, Hughes noted that these productive areas, “of course, are exploited first.”
As shale companies have chased profits, they first drilled the sweet spots, but now that most of those have been depleted, drillers must try to make a profit with Tier 2 acreage, which isn’t going so well.
Scott Sheffield, CEO of Pioneer Resources, told investors in August that “Tier 1 acreage is being exhausted at a very quick rate.”
In Hughes’ 2019 report, he maps the sweet spots of the Bakken Shale using well performance, with the highest producers shown in red.
As the Wall Street Journal noted, “Across North Dakota’s Bakken Shale region, well productivity hasn’t improved since late 2017,” with a notably dismal example coming from fracking firm Hess. Bakken wells this company drilled in 2019 “…generated an average of about 82,000 barrels of oil in their first five months, 12 percent below wells that began producing in 2018 and 16 percent below 2017 wells,” the Journal reported.
There is plenty of evidence — including warnings from industry leaders like Scott Sheffield — that the fracking industry has depleted most of the sweet spots in the major shale plays over the past decade or so. With fewer of those plum acres left, firms are forced to drill in areas with less favorable geology for production, which means spending the same amount of money to drill wells but produce less oil.
And that means shale companies have no way to pay back the huge amount of debt, which they incurred to drill the sweet spots in the first place.
Even though it began as Enron Oil and Gas, a spinoff of Enron, EOG is considered the gold standard of fracking companies and has earned the nickname “the Apple of Oil.”
The Wall Street Journal reported the declining performance of new EOG wells in the Eagle Ford Shale, noting that EOG “declined to comment” on this issue, which is rarely an indication of good news.
Many signs are pointing to the fact that geology — how much oil and gas is present in the shale — will be the defining factor going forward for the U.S. fracking industry.
In June DeSmog reported that Steve Schlotterbeck, former CEO of shale company EQT, told a petrochemical industry conference, “The shale gas revolution has frankly been an unmitigated disaster for any buy-and-hold investor…”
Those buy-and-hold investors were buying and holding companies that were drilling sweet spots. But today’s buy-and-hold investors are holding companies working with less productive shale, which doesn’t bode well for the industry’s future fortunes.
What. A. Sh*tshow. Sub $2Bn market cap E&P companies…
Most of these companies are dead men walking.
We all knew a reckoning was coming in 2016/2017 but never thought it would come with such force. Truly a bubble bursting… pic.twitter.com/QuYx1q8fWe
Chesapeake Energy’s Stock Falls Below $1 But Driller Plans to Spend Over $1 Billion on More Fracking
The company that for the past decade has been emblematic of the rise and pitfalls of shale drilling and fracking, Chesapeake Energy, saw its stock price collapse today, plunging by 29.15 percent in a single day.
At the end of the day on November 6, a share in Chesapeake (NYSE:CHK) was worth less than a buck, priced at $0.91.
How Low Can It Go?
It was the lowest stock price for the company since March 5, 1999 — and well below the $1.35 a share Chesapeake was worth on the first day its shares were listed back in 1993.
During that time, Chesapeake became the nation’s second largest producer of natural gas after ExxonMobil — a title it lost less than two years ago.
Over the past decade, the firm also racked up billions of dollars in debts, became the target of a federal antitrust investigation (settled in 2018), and was fined millions for illegally polluting water and causing other environmental harms. Chesapeake also lost its former CEO Aubrey McClendon, once hailed as “The Shale King,” who famously died in a fiery SUV accident in 2016 shortly after being indicted by the Justice Department, leaving behind a maze of debts, assets, and obligations in an estate that has taken attorneys years to sift through.
Chesapeake warned in a Securities and Exchange Commission (SEC) filing on Tuesday that if oil and natural gas prices don’t rise, the company will be at risk of a cascading series of defaults on its debts that could raise “substantial doubt about our ability to continue as a going concern.”
Roughly an hour earlier, Chesapeake reported financial results that missed analysts’ earnings expectations — meaning that it’s fallen short of Wall Street’s expectations each quarter this year.
At its peak in 2008, Chesapeake was valued at roughly $37 billion. But after more than a decade of aggressive drilling and fracking and land acquisition, as the stock market closed today, the company’s market capitalization was $1.48 billion.
The price of West Texas Intermediate oil this year has averaged over $56 a barrel (lower than last year, but higher than the average price in 2017, 2016, or 2015, following several years when oil averaged close to $100 a barrel).
For drivers, that has translated to gas prices that have stayed between $2 and $3 a gallon on average this year, according to data from GasBuddy.com.
For shale drilling companies, those prices have seemed catastrophically low.
Chesapeake Energy is hardly alone in floundering financially. In June, Steve Schlotterbeck, former CEO of EQT, which is now the largest natural gas producer in the U.S., described the industry’s decade of poor financial performance in stark terms.
“The shale gas revolution has frankly been an unmitigated disaster for any buy-and-hold investor in the shale gas industry with very few limited exceptions,” Schlotterbeck said. “In fact, I’m not aware of another case of a disruptive technological change that has done so much harm to the industry that created the change.”
Why Stop Now?
Chesapeake told investors yesterday that it planned to scale back — but not stop — its drilling and fracking operations, and that it expected to spend more than a billion dollars to keep at it.
“While we are not, I have not finalized exactly where the rig count will be next year, what we do know is that $1.3 billion to $1.6 billion will be directed across the higher-margin oil assets,” CEO Robert D. Lawler said during an earnings call on Tuesday. “So you’ll see two to three rigs in [the Powder [River Basin, in Montana and Wyoming], two to three in South Texas, two to three in Brazos Valley and two to three in the Marcellus asset.”
The company’s presentation to investors for the third quarter of 2019 indicates that in Pennsylvania’s Marcellus Shale, Chesapeake has enough land leased to allow it to keep drilling for a decade and still “break even” if natural gas prices are between $1.50 and $1.75 per thousand cubic feet (mcf). (However, investors may be forgiven some skepticism about “break-even” calculations; in December, the Wall Street Journal examined how it is that shale companies so often seem to lose money hand-over-fist even when oil and gas prices are well above their “break-even” estimates.)
The presentation shows Chesapeake has so far drilled 30 wells in the Marcellus this year, and plans to drill four more during the final three months of 2019. In Texas, Chesapeake lists 154 new oil and gas wells so far this year, plus 55 in the Powder River Basin, and 24 in Louisiana.
It reported no new wells this past quarter in its home state of Oklahoma, after reporting 14 new wells during the first half of the year.
“With massive debt, leverage is not going down every quarter you continue to outspend,” Neal Dingmann, a SunTrust Robinson Humphrey analyst told Bloomberg.
Fracking’s Debt Problem
The company needs to generate income in part because it must make payments on its debt — like many companies in the shale industry. But while the industry has doubtlessly produced vast volumes of oil and gas, it has also failed to sell that oil and gas for more money than they pumped into production, analysts say, citing the industry’s problems generating free cash flow from their operations.
“The industry is admitting what independents who drilled with industry partners early on figured out: You cannot make money drilling at this price structure,” one anonymous executive told the Dallas Fed in September, according to NASDAQ.com. “An ongoing drilling program consumes all your returns and continues to require new money.”
Some observers warned that it was far too early to call the shale rush over.
“Has every barrel of U.S. production during this period been profitable? Of course not,” the editors of OilPrice.com wrote in a piece today arguing that shale drillers will continue to pump out oil and gas despite all of their financial troubles. “But with low interest and high stock prices, shale producers should be able to source new capital to keep the pumps going. As the saying goes, never underestimate the willingness of a U.S. wildcatter to poke holes in the ground with other people’s money. With the world’s central banks once again lowering rates, ‘other people’s money’ should be plentiful.”
If things go the other direction, Chesapeake’s current sub-$1 share price suggests it could potentially wind up at risk of being delisted from the New York Stock exchange, which generally starts its delisting process once a stock trades at less than $1 for 30 days.
Back in 2011, the New York Times first reported that some industry analysts were deeply skeptical of the shale gas rush. “’Money is pouring in’ from investors even though shale gas is ‘inherently unprofitable,’ an analyst from PNC Wealth Management, an investment company, wrote to a contractor in a February e-mail. ‘Reminds you of dot-coms,’” The Times reported.
Historically, Chesapeake sought to make its money in large part by selling off its leased acreage to other drilling companies (a strategy that McClendon touted to investors all the way back in 2008, saying that “I can assure you that buying leases for X and selling them for 5X or 10X is a lot more profitable than trying to produce gas at $5 or $6/mcf.”).
But mergers and acquisition activity has slowed dramatically in the shale industry more recently, hitting their lowest point in a decade during the first three months of 2019. Activity rose in the second and third quarters of this year, but shale deals over the past three months added up to only half of the industry’s historic quarterly average.
While it’s not clear yet whether Chesapeake Energy might be dragged under by its roughly $10 billion in debts, what is clear is that the fracking pioneer has left significant environmental damage in its wake. In 2015, the Natural Resources Defense Council ranked the company its “most wanted” oil and gas company, calculating that Chesapeake had 669 spills and legal violations, more than any other driller in the U.S.
Shale Slowdown Takes Economic Toll
U.S. regions that benefited as fracking boomed are seeing declines in economic activity as producers reduce employment, spending.
America’s hottest oil-drilling regions—such as this one at the heart of the Permian Basin—are seeing their economies soften as shale producers slash spending, leading to emptier hotels, choosier employers and less overtime for workers.
Early this year, demand for the tubing, bolts and valves used in fracking was so high that Homer Daniels’s oil-field equipment company, RK Supply, in the Midland area was on track to easily beat its annual revenue forecast. But by August, Mr. Daniels had to impose a hiring freeze as customers delayed projects.
“It affects everybody’s bottom lines,” Mr. Daniels said.
Fracking has made the U.S. the world’s top oil producer, buoyed the national economy and helped the country become a net exporter of crude and petroleum products for the first time in decades. But the rapid production growth of recent years is waning as shale companies, many of which have struggled to make money, focus on profits over expansion to satisfy unhappy investors.
“The boom time is done at this point, unless oil prices go up significantly,” said Michael Plante, senior economist at the Federal Reserve Bank of Dallas.
Hotel revenue is declining in some of the hottest U.S. oil regions and flattening out in others as producers scale back to meet investor demands.
Change from previous year in revenue per available hotel room in oil producing regions
Already, that shift is taking an economic toll. National nonresidential fixed investment—which tracks spending on software, research and development, equipment and structures—fell at an annualized rate of 2.66% in the third quarter and 1.01% in the second quarter, due in large part to declines in oil and gas spending, according to the Dallas Fed.
Spending is expected to decline further next year. North American shale investment, or spending on drilling and fracking, is forecast to fall about 6% this year, then tumble another 14% in 2020, adjusted for inflation, according to energy analytics firm Rystad Energy.
Companies also are trimming jobs, leading to a 5% decline in seasonally adjusted oil-field service employment in the 12 months ended in October, according to Bureau of Labor Statistics data.
In Texas, the nation’s top oil-producing state, energy industry employment has dropped at an annualized rate of 2.1% in the year to date through September, Dallas Fed data show. Such granular figures weren’t available in other oil-producing states, but BLS data show that in North Dakota, seasonally adjusted employment in mining and logging, which includes the oil-and-gas industry, fell about 9% from January through October.
Employment Has Been Steadier In Colorado And New Mexico
The changes are evident in the Permian, the region straddling Texas and New Mexico that has been the heart of the fracking boom. Trucks carrying sand, water and crude still clog the highways, new homes continue to be built, and regional unemployment was 2.4% in October, up from a recent low of 1.9% in April but below the national average of 3.3%, not seasonally adjusted, according to the Texas Workforce Commission.
Still, oil-and-gas workers have begun to see their hours cut, and hotel occupancy in Midland has fallen 14% through the first 10 months of the year from a year earlier, according to hospitality benchmarking firm STR Inc. Occupancy had tightened during the boom, leading to high prices and a building frenzy throughout the Permian. The average cost of a room in Midland was about 55% higher last year than in 2017, STR data show.
For Jose Urteaga, a supervisor for a bulk fuel supplier, the softness has meant that his company doesn’t have to worry as much about employee turnover.
“In the past, we were just getting every warm body we could,” Mr. Urteaga said at a recent cookout in Midland. “Because it’s leveled off some, we’re able to check references, make sure guys have the experience they’re putting on their résumés.”
The slowdown is unusual because it hasn’t been driven by a sharp decline in crude prices, which have hovered around $57 a barrel this year. Rather, U.S. oil producers are paring growth and spending largely because many have struggled mightily to generate returns for shareholders and are facing tightening access to capital. Including reinvested dividends, a broad index of U.S. oil-and-gas companies’ share prices has fallen about 47% in the past three years as the S&P 500 index soared roughly 49%, according to FactSet.
“Investors are playing a large role here, and that’s the biggest driver of this cycle,” said Chris Wright, chief executive of Denver-based Liberty Oilfield Services Inc., which specializes in hydraulic fracturing. Companies such as Liberty that provide services or parts to shale producers have been among the hardest-hit by the pullback.
In Hobbs, N.M., just 5 miles from the Texas border, Kevin Mattingly, who owns Shiloh Machine, is seeing customers that used to consistently pay him within 60 days wait 90 or 100 days to do so. Meanwhile, the pile of tubing and other tools that companies have asked the machinist to repair is dwindling.
“There is a crunch on our cash,” Mr. Mattingly said. He recently asked employees to stop working overtime, a key source of income in oil boomtowns, where costs run high and housing can be difficult to find.
On the Texas side of the Permian, Scott Chaffin is planning to go back to school in January for welding, after seeing his weekly hours at a pipe-inspection company fall to about 50, from more than 80 earlier this year.
“You’ve got to pay attention a lot more to your spending,” said Mr. Chaffin, 34 years old, who has cut back on expenses such as new clothes and eating out.
Banks Get Tough on Shale Loans as Fracking Forecasts Flop
Oil and gas companies face tightened credit after wells produce less than projected
Some of the banks that helped fuel the fracking boom are beginning to question the industry’s fundamentals, as many shale wells produce less than companies forecast.
Banks have begun to tighten requirements on revolving lines of credit, an essential lifeline for smaller companies, as these institutions revise estimates on the value of some shale reserves held as collateral for loans to producers, according to people familiar with the matter.
Some large financial institutions, including Capital One Financial Corp. and JPMorgan Chase & Co., are likely to decrease the size of current and future loans to shale companies linked to reserves as a result of their semiannual reviews of the loans, the people say. The banks are concerned that if some companies go bankrupt, their assets won’t cover the loans, the people say.
White House To Tap Oil Reserve Again Amid High Fuel Prices
* Gas, Diesel Export Limits Decision Unlikely Before November
* Klain Says Biden Will Speak On Gasoline Prices Wednesday
The Biden administration is moving toward a release of at least another 10 million to 15 million barrels of oil from the nation’s emergency stockpile in a bid to balance markets and keep gasoline prices from climbing further, according to people familiar with the matter.
The move would effectively represent the tail end of a program announced in the spring to release a total of 180 million barrels of crude from the Strategic Petroleum Reserve. About 165 million barrels has been delivered or put under contract since the program was put into effect.
The Biden administration also is set this week to provide details on plans to replenish the emergency stockpile. The Energy Department announced in May it was planning a new method of buybacks to allow for a “competitive, fixed-price bid process,” with prices potentially locked in well before crude is delivered.
President Joe Biden will speak about gasoline prices on Wednesday, White House Chief of Staff Ron Klain said in a tweet.
The announcements will be part of Biden’s response to the ongoing effects of Russian President Vladimir Putin’s invasion of Ukraine, a senior administration official said. The administration also seeks to address anxiety about stubbornly high gasoline prices ahead of midterm elections next month and historically constrained supplies. Heading into winter, the US has the lowest seasonal inventories of diesel, according to data first compiled in 1982.
Separately, the administration is still weighing limits on exports of fuel to keep more gasoline and diesel inside the US, according to two of the people, who weren’t authorized to speak publicly about internal deliberations. Although no timeline has been set for a decision on that potentially more dramatic step, it wouldn’t happen before November’s midterm elections, one of the people said.
The export control idea, which would be temporary, has sparked division within the administration, as top Biden energy adviser Amos Hochstein argues in favor of new export controls even as Deputy Energy Secretary David Turk has expressed concerns, said people familiar with the matter. Other White House officials, including Klain and National Security Adviser Jake Sullivan, have yet to make a recommendation.
Energy Department and White House officials have been quietly meeting this week with oil companies, including Exxon Mobil Corp. and ConocoPhillips, to notify them of what to expect while continuing to encourage additional production of oil and refined fuels.
Oil industry representatives and third-party energy analysts have cautioned that limiting fuel exports could lead to higher prices in parts of the US, particularly in the import-reliant Northeast.
Spokespeople for the White House didn’t immediately comment. The Energy Department referred to a previous comment from earlier this month that asserted the administration was going to look at all tools available to protect Americans and uphold commitments to allies.
Republicans have made rising gasoline prices and inflation the centerpiece of their campaign to take control of Congress in the elections. The White House has been seeking to ease rising costs at the pump and bolster low domestic stockpiles of fuel while also responding to the OPEC+ coalition’s decision earlier this month to slash production.
Gasoline prices, one of the most visible signs of inflation, are a political headache for Biden, who in recent weeks has repeatedly warned oil companies against raising costs. Average US gasoline prices were slightly lower at $3.87 a gallon on Monday, according to data from auto club AAA.
“The price of gas is still too high and we need to keep working to bring it down,” Biden said at an event in Los Angeles last week.
White House economic adviser Jared Bernstein said Sunday that Biden hadn’t yet made a decision on an SPR release. The reserve, which has the capacity to hold about 714 million barrels, contains 405.1 million barrels, as of Oct. 14.
“The fact is there is capacity to use the SPR to deal with some of the energy shocks we’re seeing in the world. But I’m not saying we will. That’s up to the president to decide, he hasn’t made that decision yet,” he said.
The White House had indicated that further SPR drawdowns were a possibility shortly after the OPEC+ announcement.
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