NEW YORK (Reuters) - Occidental Petroleum was among the first major U.S. oil drillers to make a big bet on the resurgence of domestic production, spending billions to grab oil patches from Texas to North Dakota.
Now, as it bemoans steep costs and moves its rigs out of the Bakken shale oil fields, some analysts wonder if the company has lost its clairvoyance. After two years of unyielding gains, costs are bound to fall, they say.
The California-based energy giant is beset by escalating labor costs in North Dakota, which has the lowest unemployment rate in the country. Other material costs have surged and new environmental regulations could add to the burden. The cost of bringing one Bakken well into production has grown from an average $6.5 million in 2010 to $8.5 million in the first quarter this year, data from company reports and the state regulator show.
“We got a lot better places to put money right now than the Bakken,” Occidental CEO Stephen Chazen said on a conference call with analysts late last month. “That’s why I’m slowing it down.”
But if some analysts are right, Occidental’s pullout may prove ill-timed. The costs to complete a well by injecting it with water, sand and other chemicals — the hydraulic fracturing or “fracking” process — is falling as natural gas firms pare back on new drilling.
Pressure pumping prices, which cover a range of costs associated with fracking a well, have already dipped by up to 25 percent in natural gas-rich basins, with signs of a knock-on effect emerging in the Bakken, according to Barclays analysts. Within the next six months, these costs could fall by as much as 10 percent in the Bakken shale, analysts at Bernstein Research estimate.
Efficient forms of fracking are also helping companies extract more oil from each well, lowering the break-even cost of production, now estimated between $55 and $70 a barrel.
The push and pull of production costs in the world’s fastest-growing oil frontier is adding uncertainty to the outlook for U.S. oil prices. The issue is already in the limelight this election year, with both political parties touting shale oil as a step toward energy independence, even as environmentalists fret over the controversial fracking process, which has been blamed for the pollution of water supplies and minor earthquakes.
If costs start to slip, the explosive output growth could keep a lid on U.S. oil prices, regardless of tensions with Iran that have threatened global supply. If they continue to rise, breakneck output growth may stall as more companies follow Occidental’s lead and begin to pare back drilling and investment.
The two biggest plays — the Williston basin in North Dakota and Eagle Ford in Texas — produced an estimated 1.2 million barrels per day (bpd) in April, close to the output from OPEC member Algeria, according to data from analytics company Bentek Energy. A year ago, they were producing only a third as much.
Over the past three years, drilling in U.S. shale patches has become an expensive affair, even as producers got better acquainted with the shale rock they mined. Service firms could name their price while the producers scrambled to drill.
Sand and ceramics, which companies pump into deep wells in a water and chemical mix to frack a well, were in scant supply. The spot price of guar — a gum processed from tiny seeds and used to thicken fracking water — has ballooned by 10-fold since January 2011 and doubled since the start of this year, according to data from Agra Informa, an agricultural consultancy.
The nationwide cost of drilling and other well services for oil and gas wells has risen 22.5 percent since October 2009, hitting a five-year high in March, according to the Bureau of Labor Statistics’ Producer Price Index (PPI).
Meanwhile, prices for shale oil, particularly from the Bakken, fell as the glut of new crude supplies in the Midwest led to deep discounts for U.S. benchmark crude.
Bakken crude for June delivery at the Clearbrook, Minnesota hub was bid as low as $85.24 a barrel on Wednesday and offered at $93.69, down 6.5 percent from October levels, according to traders. For now, prices are comfortably above the $68 a barrel breakeven point for a 15 percent rate of return, according to Credit Suisse analysis.
But this year’s slump in natural gas prices to a 10-year low is beginning to change the game. Pricing power is shifting from service companies to drillers, possibly capping costs, as energy firms slash gas-directed drilling rigs by 23 percent.
Houston-based oil services firm Baker Hughes projects the number of rigs drilling for both oil and gas at the end of 2012 will be just under 2,000, only one percent higher than last year.
At the same time, total U.S. pressure-pumping capacity is expected to grow to 19 million horsepower this year, two-and-a-half times the levels three years ago, according to research firm Tudor, Pickering, Holt & Co.
Some of this new capacity is operated by small fracking firms that are mushrooming across North America who are willing to take on projects for a fraction of what the big firms charge.
What is more, fracking crews, previously engaged in dry-gas outposts, are already moving out of east Texas and Louisiana and into the hyperactive Eagle Ford shale in south Texas or the Bakken up north.
Bad news for oil-services firms also highlights the trend. Halliburton, the market leader in pressure pumping, lost 5 percent of its operating income in North America in the first quarter of 2012, compared with the previous quarter, as the price it charged for pressure pumping slumped.
The company said its North American margins will fall into the low 20 percent range by the end of 2012, down from about 25 percent at present.
Efficiency is also improving. Whiting Petroleum, one of the largest producers in the Bakken, says it has cut the days it spends drilling wells to 15, which shaves off about $1.5 million in costs. The company also uses a fracking method called sliding sleeves that adds another $1.5 million in savings, according to CEO Jim Volker.
He says Whiting’s average well costs vary from $6 million in the sweet spots of the Sanish field in central Bakken to $7 million elsewhere in North Dakota.
Other input costs may also be poised to decline.
EOG Resources says it is spending $500,000 less on each Eagle Ford well after it started using sand from its own mines in north-central Texas and Wisconsin. The company says its well costs in the south Texas play average $5.5 million per well, giving it a $1.5 million edge over other operators there.
EOG’s Wisconsin mine, which started operating in January, is one of the 20 new sand mines that popped up in the state since last year. Neighboring Minnesota has 13 pending applications for new mines but most of these were stopped short by county-level moratoriums that will be in effect well into next winter, according to Tony Runckel, the state’s chief geologist.
While sand or “proppant” prices haven’t fallen yet, input prices are likely to decline later this year, according to Barclays analysts James West.
US Silica, one of the largest frack sand producers in the United States, is tying up more long-term contracts, a sign that it is also anticipating a possible downturn in prices.
Guar supply is another issue. Indian farmers, who cater to 80 percent of worldwide guar demand, are sowing record volumes of the seed this season but it is not entirely clear if this autumn’s harvest will meet growing U.S. demand.
Even though cost declines are on the horizon, they may be slow to arrive.
New state regulations in North Dakota, put in effect at the start of April, could add up to $400,000 to the cost of each well, since they proscribe the use of reserve pits to store discarded drilling fluids, according to the state Petroleum Council, which represents producers.
The long-term contracts that many developers have with the oil services firms will also stand in the way. Those contracts, which ensured steady prices when costs were on the up, are a long way from their end and, in most cases, are unlikely to be renegotiated soon.
Houston-based driller Marathon Oil said its first-quarter well costs in the Eagle Ford were unchanged at $8.5 million a well because of such contracts, which the company’s Chief Operating Officer, David Roberts, said are keeping his firm from “as much price relief, potentially, as we would like.”
Halliburton, in fact, says it is going back to producers, with steeper price schedules in tow, so it can pass on some of the lofty raw material costs, its CEO David Lesar said in April.
“I suspect the pressure will come when they start to roll over” the contracts, Lesar told analysts last month.
In the Bakken shale, that could be as far out as eighteen months into the future, according to James Crandell, global head of oilfield services research at Dahlman Rose in New York. Even then, Crandell says, contracts will be renewed at “modestly lower” prices in North Dakota.
“In other regions, particularly natural gas (fields), I expect larger reductions when the contracts end,” he added.
Still, even Occidental does not intend to fully move out of oil-rich shale plays like the Bakken.
“This is the Willie Sutton discussion,” CEO Chazen said, comparing his strategy with that of the slick bank robber from Brooklyn. “Why are we there? Because that’s where the oil is.”
(This version of the story has been corrected to fix the name of Occidental’s CEO)
Additional reporting by Braden Reddall in San Francisco and Jeffrey Jones in Calgary; Editing by Marguerita Choy