The shale revolution is “a little bit overhyped,” Shell CEO Peter Voser said last week as his company announced a $2.1 billion write-down, mostly owing to the poor performance of its fracking adventures in U.S. “liquids-rich shales.” Which of its shale properties have underperformed, Shell didn’t say, but CFO Simon Henry admitted that “the production curve is less positive than we originally expected.”
Shell was a latecomer to the tight oil game. As late as 2010 it was acquiring mineral rights at inflated prices, predicting that those properties would produce 250,000 barrels per day in five years. Three years down the road, they are yielding only 50,000 barrels per day, and the company intends to sell half of its shale gas and tight oil portfolio. Shell has officially abandoned its production target of 4 million barrels per day by 2012-2018. Instead, Voser said, “we are targeting financial performance.”
Second-quarter earnings were dismal for the so-called oil supermajors. Shell, BP, Exxon Mobil, Chevron, Total SA, Statoil, and Eni SpA all reported sharply lower profits.
Production was also down nearly across the board, with only Total SA reporting an increase.
Of course, none of this would be a surprise for those who read my article from March, “Oil majors are whistling past the graveyard.”
The declining profitability and production primarily owed to lower oil prices and rising costs. As Platts reported in June, total capital spending for the top 100 U.S. producers in 2012 rose 18 percent year on year. Costs will be higher still this year.
Rising costs are partly due to the tight oil boom itself. Producers that invested heavily in tight oil production are struggling to maintain output against the accumulating undertow of existing wells, where output declines rapidly. Geologist David Hughes finds an average decline rate of 60 percent to 70 percent for the first year of production in new wells in the Bakken shale of North Dakota. And a new statistical analysis by Rune Likvern at The Oil Drum shows production from most Bakken wells falls by 40 percent to 65 percent in the second year.
Source: Rune Likvern, The Oil Drum
For the Bakken field as a whole, Hughes calculated an annual production decline rate of 40 percent per year in his February report, Drill, Baby, Drill.
The problem is obvious. Decline rates that sharp make tight oil production a treadmill that speeds up a little more every year. Producers have to keep drilling more each year to simply keep output flat. That increases costs.
Other factors contribute to rising costs across the industry globally, including the ever-increasing difficulty of finding new prospects, and overall price inflation for basic commodities like cement and steel.
A good summary by Tom Fowler and Daniel Gilbert in the Wall Street Journal quotes analysts at Bernstein & Co. who see trouble ahead. "This cannot continue. . . . As long as oil prices stay flat and costs continue to rise, it will be impossible for the industry to sustain the current levels" of spending. If their spending drops off, production will too."
One thing that doesn’t help the cost curve is unprofitable investments, and some of the newer tight oil plays aren’t panning out as hoped. In April, Bloomberg reported that the four biggest stakeholders in the Utica shale of Ohio were divesting, due to “disappointing” results. And the Monterey shale in California has continued to prove troublesome.
A growing consensus suggests that only the Bakken, Eagle Ford, and Permian formations will be major tight oil producers.
As for the Bakken, its heady days of skyrocketing growth appear to be over. Production growth stalled in early 2013 despite the continuous addition of new wells, as this new chart by Hughes shows.
Source: David Hughes
Drilling activity is slowing down in North Dakota. Drilling permit applications are down, and it’s taking longer to bring new wells into production. The state Department of Mineral Resources says investors are “nervous” about tax policy and regulation, but that might not be all they’re nervous about.
For one thing, newer wells aren’t as productive as earlier wells. As I have explained previously, this is because producers drill the most productive “sweet spots” in a shale play first, then move out toward the periphery, where the quality of the shale is lower. (Despite some producers’ claims to the contrary, shale plays are not uniformly prospective. Significant areas of the shale plays may be unproductive.)
In Likvern’s chart below, note how production from wells of 2011 vintage (red line) has fallen below that from wells of 2010 vintage (turquoise line).
Source: Rune Likvern, The Oil Drum
The falling productivity per well was somewhat masked by the sharp increase in drilling in 2011 and early 2012, which drove overall Bakken production higher.
Source: David Hughes
But by mid-2012 drilling began to fall off, and the declining productivity of new wells began to become evident. To borrow a quote from Warren Buffett, “you only find out who is swimming naked when the tide goes out.”
Hughes estimates that it now takes about 120 new wells per month, or 1,440 per year, to offset decline in the Bakken. So of the 720,000 barrels per day produced from the Bakken in April, 319,000 barrels per day will be lost to decline this year. But as the above chart (through April, 2013) shows, fewer than 120 wells per month were added toward the end of the first quarter. Consequently, Bakken production has tapered off over the past six months as the undertow of depletion overcomes new well additions. Production from the field will continue to decline unless drilling picks up again.
Production is still growing in the Eagle Ford shale in Texas, where new wells are being added at a rate of nearly 3,000 per year.
Source: David Hughes
But again, the increase in production per new well has been falling.
Source: David Hughes
Prices are going higher
To be clear, smaller companies who are extremely focused on U.S. tight oil exploration are still turning profits. Tight oil production is still growing, and should continue to grow for several more years at least, just not as quickly as it has for the last several years. However, I am dubious about its production increasing from a bit over 2 million barrels a day today to 5 or 8 million barrels per day by 2020, as some have forecast.
We’ll probably drill around 19,000 horizontal wells this year, which will push production another few hundred thousand barrels per day higher. But we’re not going to raise production by a million barrels per day in a year anymore.
And it’s gonna cost ya. U.S. oil prices have bounced around $95 this year (as I predicted) but that has not been high enough for Shell to make money in tight oil and shale gas. It has not been high enough to sustain high drilling rates in the Bakken. It has not been high enough for most of the supermajors to turn a profit.
The decline in Bakken drilling could have been partly due to the glut at the Cushing, OK delivery point, which forced Bakken producers who ship by pipeline to accept a steep discount. (Bakken producers who shipped by rail directly to coastal refineries could fetch higher prices.) That is now partially relieved due to new pipeline capacity, and U.S. oil prices have risen back to global price levels. That may spur a new uptick in production as we head into the end of the year. As I explained in my last column, tight oil production supports price, it doesn’t reduce it.
But the decline in Bakken drilling can’t be wholly explained by the temporary glut at Cushing. The entire U.S. tight oil boom appears to be running into more systemic problems.
Analyst Bob Brackett of AllianceBernstein says, “the prime locations have already been drilled” in U.S. tight oil plays, and that drillers are moving on to less prospective areas. He sees the U.S. oil price benchmark WTI averaging $103 per barrel in 2015, while the European benchmark Brent rises to $113.
Source: Bernstein Research
Rising costs across the industry, and declining profitability for the supermajors in an era of triple-digit global prices, suggest that oil prices need to be higher to maintain output. Since domestic gasoline and diesel prices, which are strongly linked to global prices, have remained stubbornly high even while U.S. oil prices were falling this year, that suggests we will likely see gasoline prices pushing toward $4.50 a gallon next year in higher-priced U.S. markets like San Francisco and New York City.
From an oil booster’s perspective, drilling 19,000 new horizontal wells (and 35,000 new wells in total) this year is a good sign. But regular folks might want to think about how much longer such a frenetic pace can go on, about the incursion of fracking into their backyards, about the environmental cost, and about the financial cost of keeping the “bonanza” going.
There is trouble in fracking paradise. A $2 billion write-down by Shell doesn’t quite spell the end of the U.S. oil boom, but it doesn’t bode well either. The "Saudi America" craze was cute, but that slogan isn’t going to make you any happier when you’re shelling out $4.50 and more for a gallon of fuel.
Want my advice? Get a more efficient vehicle. Don’t settle for less than 40 mpg. If your habits and pocketbook allow, consider an electric vehicle. And if energy independence is really your thing, then make it an EV with a rooftop solar PV system. That’s your best protection against the persistently rising cost of fuel.
My thanks to David Hughes and Rune Likvern for their contributions to this article.
Photo: Old pumpjack in East Texas (rcbodden/Flickr)