The U.S. has undergone the kind of dramatic makeover that's typically reserved for TV reality shows. The mining of unconventional shale gas, light and tight oil–enabled by horizontal drilling and hydraulic fracturing–has sparked an energy revolution.
In 2005, when these unconventional wells were first drilled in the Barnett Shale basin around Dallas-Fort Worth, America was the world's largest oil importer and domestic production had been in decline for three decades. That's now reversed. We're producing 8.5 million barrels daily and until recently many expected us to break the U.S. production record of 9.6 million barrels set in 1972.
Gas output has increased by one third and total petroleum output (including oil, gas and condensates) by almost three-fourths in just six years. We now drill more oil and gas than anyone in the world–topping even Russia and Saudi Arabia. Two-fifths of it comes from Texas. The energy industry employs twice as many people as it did nine years ago, and it contributed 0.3 percent to last year's gross domestic product.
There's no denying the turnaround; the question is how long it will last. Texans are more familiar than most with boom-bust cycles, so the quantity of sunshine being bussed up our backside might raise an alarm or two. Much of the boom is fueled by cheap credit, unrealistic expectations and lots of excess capital swishing around in search of good yields.
"Very little of this would be going on if you had to pay 3-4 percent interest on money that people gave you," said Houston energy consultant Arthur Berman. "Whenever interest rates are really, really low, people spend money on really stupid stuff. And most of these companies are going to pay you an interest rate that beats the pants off a savings account or a CD [certificate of deposit]. So the world has found what they consider a reasonably secure way to get anywhere from 6 to 9 percent interest."
The Price of Being Different
The fundamentals of unconventional wells are distinctly different from those of conventional wells, and this has contributed to the shale bubble's inflation. Unconventional wells are expensive to drill and run down quickly, and fracking, as it's known, requires constant capital investment to maintain production levels.
Fracking wells are drilled at an angle and chemical slurries are pumped deep into the ground to break up the thick shale deposits, freeing the gas and oil trapped inside the rock. It's an expensive process. The cost of drilling a horizontal well averages $6-$8 million, compared to $1 or $2 million for a conventional well.
The wells gush hard when they're first drilled, but lose around 40 percent of their capacity each year. By the end of the third year the flow is one quarter what it once was. That means to maintain production levels companies have to keep drilling more wells. In fields like the Eagle Ford and Bakken, four-fifths of new production replaces the output from already depleted wells. In the industry it's known as the Red Queen syndrome, after Lewis Carroll's Through the Looking Glass character, who complains, "It takes all the running you can do, to keep in the same place."
The best output comes from "sweet" spots, which are twice as prodigious as the rest of the field. Companies attempt to locate these first since they're the most profitable wells to drill. But the fact that the best spots go first only exacerbates the depletion issue since those wells become increasingly more difficult to replace.
"As you move out you start dealing with fringier and fringier acreage. The costs of the wells generally go up because you're drilling longer laterals with more fractures," Bill Powers, author of Cold, Hungry and in the Dark: Exploding the Natural Gas Supply Myth, said. "You can keep the production stable as you move out, but eventually geology trumps technology, and the wells get more expensive while putting out less."
This explains the hushed skepticism among industry insiders. In a series of emails among industry executives exposed in 2011 by The New York Times, an official at IHS Drilling Data mused, "the word in the world of independents is that the shale plays are just giant Ponzi schemes and the economics don't work."
It's important that the companies active in the shale keep drilling quickly enough to maintain or increase production. That hides the unprofitability of the wells and keeps their debt-fueled expansion going. The problem is that once production levels stagnate, Wall Street frowns, and those "buy" analyses turn upside-down. Then the money to fund all that drilling dries up. That's why the pressure is on to maintain the hype. Bloomberg reported in October 2014 that 62 of the 73 shale drillers gave investors resource estimates on average 6.6 times higher than proven reserves reported to the Securities and Exchange Commission.
That's the nature of the game, according to former investment banker and energy-industry analyst Deborah Rogers. "Publicly traded companies have two sets of economics: field economics for oil and gas companies–what are the underlying wells doing, what are my costs on the field–[which] are totally separate from what I call 'street economics,'" she said. "That's where you start seeing creative accounting in order to keep the analysts interested in your stock, keep your financials looking like you're meeting those metrics and keeping your bankers happy. ... "Those two things don't necessarily jibe."
Fake it Till You Make It
So far the spin job has worked. More than $16.3 billion was invested in mutual and exchange-traded funds focused on energy companies in the first seven months of the year–twice as much as the same period last year, according to analysts Strategic Insight.
Yet the underlying figures are ominous. Shale debt has doubled over the last four years while revenue has inched up just 5.6 percent, according to a May Bloomberg analysis of 61 shale drillers. A dozen of these independents were spending at least 10 percent of their sales servicing their debt. Some, like Forest Oil, Goodrich Petroleum and Quicksilver Resources, were paying interest expenses in excess of 20 percent. Many companies are spending more than they're taking in, and this negative cash flow has not improved, even as investment continues to pour in.
"You can have negative free cash flow for a short period of time, but when it turns into a long-term pattern there is something very wrong," Rogers said. "The other problem with these companies is that most of it is junk debt. You've got low-quality credit and very high levels of it."
This is such speculative debt that banks can't buy it, leaving companies to lure other investors with high yields. In the first quarter of the year independent U.S. oil and gas producers sold $2.3 billion of such bonds, about half of all the corporate bond debt they issued. About 80 percent of the 115 exploration-and-production firms Moody's Investors Service follows and 70 of the 97 companies Standard & Poor's evaluates are junk-rated.
Independents aren't the only shale players who are struggling. During the past 18 months, major players have taken huge write-downs on shale. Sumitomo took a $1.55 billion write-down on its joint venture with Devon Energy in West Texas' Permian basin. In April, BP wrote off half-a-billion in Ohio. Last year Shell wrote off $2 billion and sold 100,000 acres it had acquired in the Eagle Ford basin. Marathon also wrote down $340 million of acreage in counties like Bee, DeWitt, Lavaca and Wilson.
Of course, the major oil companies were latecomers to the shale party. They didn't tend to get the prime acreage or the low prices that help ensure success for those early to the play. Nor are the majors necessarily built for it. "The business model that supports the major oil companies is predicated on size and scale," said former Shell CEO John Hofmeister. "That's the antithesis to shale plays where the independent operator has a business model that is based on move quick, drill it now and get on to the next one."
The question remains–do these smaller independents have the wherewithal and, more importantly, the capital, to withstand the incipient fall industry analyst Tim Morgan described as "this decade's version of the dotcom bubble?"
Gas & Go, Going Gone
It's also important to make a distinction between gas and oil because those economics differ, too. Oil's relatively high price makes it significantly more economical than gas–for the moment. It wasn't always this way.
Indeed the first unconventional wells were typically focused on gas. Oil only began to predominate in the shale after gas producers screwed themselves with overproduction. Propelled by natural-gas prices that rose to $13.50 per million Btu (MMBtu) in 2008, everyone dove headlong into the shale gas game. Within four years the market was flooded, sending prices down to $2 before they crawled back up to the present $3-$4 range.
"It was almost like the banks encouraged them," Rogers said. "They had to meet production targets so the analysts would keep giving them buy ratings and so they overproduced. Anybody could see where that was going to go."
The banks make their money on fees. So whether investors are buying or selling, as long as there are mergers and acquisitions, the banks stay flush. They can keep activity high by feeding the speculative froth.
"They're publishing research for a reason," Berman said. "It's not a public service."
The field is so capital-intensive that shale drillers can't afford to be too price-sensitive. They have to drill to service the debt, though they'll hew to the sweet spots if they can. The volatility and need for capital leads many companies to massage their bottom line with off-the-books financing schemes. These include hiding expenses in shell companies and the dubious practice of selling future well production.
The poster boy for this kind of sketchy behavior is former Chesapeake CEO Aubrey McClendon, who over-leveraged his company, driving it from a high of $69 per share in 2008 to $13.55 at its 2012 low ebb. McClendon was booted later that year after it was revealed he'd borrowed $1.1 billion against his personal stake in Chesapeake to fund a money-making perk in his contract, creating dramatic conflicts of interest.
"Chesapeake was the worst offender far and away," Rogers said. "But other CEOs were watching to see what they could get away with and then they oftentimes copied him after that. It was, 'Let him go out there because he's the consummate promoter.'"
Berman notes that the cash flow of 24 gas-dominant companies he follows–among them Anadarko, Devon Energy, Range Resources, XTO and Cabot Oil and Gas–is collectively $8 billion* in the red over the last four years, and they're $85 billion in debt.
"Anyone that wants to make a case these guys are making money needs to explain that," Berman said. "These are real companies and they're losing their asses. Everybody assumes they wouldn't be spending money if they weren't making money, but everybody said the same thing about Merrill Lynch, Bear Stearns and AIG."
Oil Wells That End Well?
When shale gas producers did their lemming-like header into the drained pool, every company that could moved into the oil-dominant end of their acreage. But even these "wet" wells produce a good quantity of gas, which has prevented natural-gas prices from rising too high and suddenly shale oil producers find themselves compromised by the same issues that bedeviled shale gas.
The shale boom has allowed America to cut our petroleum imports from 60 percent to 30 percent, which combined with slow global growth (particularly in China) created an oil glut on the world market. In the past four months the price of benchmark West Texas Intermediate petroleum has fallen by 20 percent to $80 a barrel. Last month Goldman Sachs and Bank of America suggested the price would sink below $75 by next year. Rather than cut production, the Saudis have signaled they'll let the price fall.
T. Boone Pickens and others have suggested this could be part of a Saudi plan to squeeze U.S. shale oil producers who have much larger marginal costs. Ed Hirs, University of Houston energy economist and head of independent energy company Hillhouse Resources**, believes the Saudis' behavior has more to do with the relative strength of the U.S. dollar, which has lured foreign investors, in turn causing the dollar to rise in value against other currencies. Since oil is sold in dollars, the dollar's strength makes oil imports increasingly expensive for other countries.
"Any significant price increases are going to beat the holy hell out of demand," Hirs said. "We saw that last summer as India and Pakistan began to drop the demand as the dollar got stronger. Oil imports into India and Pakistan fell by 20 percent."
That pushes many producers up against their break-even point. Two weeks ago, a report from Sanford C. Bernstein & Co. suggested that a third of U.S. shale production is uneconomic at current price levels, let alone $5-$8 dollars cheaper.
Shale oil producers are enduring the same situation gas producers faced a couple years ago with one frustrating little difference. "Oil at $80 is going to have a big impact," Powers said. "They can no longer subsidize gas-drilling. They're so heavily leveraged production will drop off massively, which is going to have a big negative effect on these companies' abilities to generate cash flow. That is what will accelerate the end of the boom."
What This Means for Us
San Antonio and the surrounding area have already benefited greatly from the Eagle Ford play. In September, Dr. Thomas Tunstall, research director of the UTSA Institute for Economic Development, released a study indicating that the Eagle Ford had generated $87 billion in economic output, supporting 155,000 jobs and providing $4.4 billion to state and local governments in 2013 alone.
Tunstall doesn't believe Eagle Ford production is in trouble at $80 a barrel, but expects production cuts should it get close to $70. Overall he's bullish on the prospects for the Eagle Ford, noting that it's a relatively new play that's already producing 1.5 million barrels a day and has consistently beat projections.
"I was skeptical. It wasn't until I started running the numbers that I came around," Tunstall said. "All I know is the production is continuing to outstrip on what I would've thought were pretty aggressive forecasts."
Even if some of the companies working the Eagle Ford run into trouble with financing, that doesn't mean there will be the kind of bloodbath that resulted from the financial crisis. "I'd be cautious about predicting some sort of collapse even though these companies look shaky," Berman said. "What happens if a particularly shaky company gets into distress, probably somebody is going to buy them, maybe at a discount."
Aside from the risk this poses for those involved in the oil and gas trade, the fall in price of petroleum and natural gas will be a boon for many people's pocketbooks. Gas priced below $3 per gallon is sure to encourage economic growth and low natural-gas prices have already encouraged other types of investment, such as the building of several new U.S. steel mills.
Landowners who have leased to drilling companies will likely feel the pain of lower production. Chesapeake is facing multiple lawsuits over allegedly exorbitant "gathering" fees they've deducted from landowner royalty payments. More companies could try to pass their costs along to lessees.
Production cuts could also mean lower tax revenue than municipalities are counting on. Rogers points to North Dakota, which has taken in $3.5 billion from drilling in the Bakken play to cover what their Department of Transportation estimates as $7 billion in road damage.
"There's some economic benefit when shale comes to town, it's just not long-run," Rogers said. "Is the economic benefit you're going to receive really going to be enough to offset all the environmental degradation and road damage? From the numbers I've run, you don't make enough money off it."
Looking Out Toward the Horizon Line
No one can say for sure how long the shale boom will last, even accounting for the troubled financials of some companies. The well-respected International Energy Agency forecasts that shale production will peak just three years from now. Even they see a production plateau in the offing, citing "a rising percentage of supplies that require a higher break-even price; increased focus on cash flow rather than acquiring new acreage by producing companies; higher interest rates that increase financing costs for new drilling; and reduced resource estimates."
According to Canadian geologist J. David Hughes, average well production in the Eagle Ford increased only marginally in the last year, indicating that producers have begun to saturate the sweet spots. "Well quality is peaking," he said. "[But] there are still lots of places to drill in the sweet spots."
Hughes studied every well in every shale play for last month's report, Drilling Deeper: A Reality Check on U.S. Government Forecasts for a Lasting Tight Oil & Shale Gas Boom. He echoes the I.E.A. 2017 shale peak and foresees a similar peak for the Eagle Ford. UTSA's Tunstall doesn't think the field will peak until 2020, at 2.6 million barrels. Even Hughes' more pessimistic view predicts Eagle Ford production will peak at 1.7 million before sinking back to the current level of 1.5 million by 2024.
The problem is that while everyone acknowledges the quick depletion rate of unconventional wells, many, including Tunstall, forecast well lives of 20 or 30 years, in line with conventional wells. This form of drilling has been around for less than a decade and evidence is scarce, but Hughes notes that even though depletion rates stabilize at 10-15 percent after the fourth year that's more than the single-digit average rates of conventional wells of the same age.
Fort Worth native Rogers suggests we simply look to her hometown, where the Barnett play kicked things off. "The city of Fort Worth got approximately $50 million for 40 shale wells in 2008," she recalled. "Everyone was convinced they were going to be 'shale-ionaires.' But by the end of 2012, the city got about $20 million, but now we have 400 wells. They just can't keep it up.
"So you have all these pretty big pad sites and there's no reclamation plan in place," Rogers said. "Land could have been used for activities that would've generated taxes for a long time to come, and now it's used up in five to seven years and then there are no taxes generated off it. It's just useless land."
Eagle Ford producers are adding around 3,500 wells annually and the total number is expected to reach 40,000 wells. Since 1992, Texas has spent more than $60 million to clean up approximately 5,000 oilfield sites, and has $19 million on hand. Clearly, they'll need a lot more money for reclamation before it's all said and done.
Municipalities, too, must prepare for the inevitable bust.
"It's clear what the energy companies want to get out of this and they're happy to help where they can, but the real impetus for sustainability has to come from the community leaders," Tunstall said.
That's why it's important to keep the shale boom in context and not get caught up in the hype. Berman would rather not be the bearer of bad news, but somebody needs to stop the emperor from streaking around town.
"People ask me, 'What's your motive? Do you like to bum everyone out?" he said. "That's not what I like to do. My point is that the same way we make bad investments when money's cheap, we make bad decisions when we think we have a situation licked and under control. I'm just trying to give an accurate picture of what's really going on."
*Correction, November 5, 2014, 4:14 p.m.: Art Berman was incorrectly quoted as saying $67 billion instead of $6 to $7 billion. The latest figure he gave the author was $8 billion in negative cash flow.
**Correction, November 5, 2014, 4:14 p.m.: The original version of this story misidentified Ed Hirs as a consultant. Hirs is a University of Houston energy economist and head of independent energy company Hillhouse Resources.
