NEW YORK (Reuters) - North Dakota crude oil prices tumbled this month to below the $80-a-barrel “sweet spot” that helps drillers attract capital from other shale areas, yet the Bakken boom shows no signs of slowing.
Even though prices have slumped to their lowest in more than a year, output keeps marching ahead thanks to falling operational costs, increasingly efficient well technology, rising reserve estimates and aggressive forward hedging programs. Experts say the 1 million barrel per day (bpd) mark will probably be reached by early next year.
Local cash prices, which have fallen some $25 a barrel in the past two months, would have to suffer a sustained decline to $70 a barrel or lower to jeopardize near-term spending, analysts said, a prospect most deem unlikely for the moment.
“There’s only one Bakken. It’s the most important oil discovery in the past 50 years,” said Harold Hamm, the founder of Continental Resources CLR., earlier this month.
“And it’s just getting started.”
Bakken operators included Whiting Petroleum (WLL.N), Hess (HES.N) and EOG Resources (EOG.N) showed no signs of concern over oil prices in conference calls this month. Mark Papa, Chairman of EOG, said that the firm would like “ramp up” activity next year if prices simply remained steady.
Yet the risks of a downturn in prices are more pronounced for the booming U.S. shale fields of the Bakken and the Eagle Ford in Texas than for multibillion-dollar global mega-projects that take years to develop and pump crude for decades.
Unlike conventional oil development, shale is more like a production line, with daily drilling needed to offset falling output from just recently completed wells. This calls for more frequent assessments of commercially viability.
One challenge of predicting the U.S. shale boom is its variability. Well costs and rates vary wildly between companies even within the same reservoir, making it hard to say how and when operators will respond to swings in oil prices.
On Wednesday, Bakken cash crude oil prices at the Clearbrook, Minnesota, hub traded at $14 a barrel below U.S. futures, or $79.75 a barrel. They touched $77.90 on November 5, the lowest since July 2012. Prices averaged $94 for the first eight months of 2013 compared with $86 in the second half of 2012.
“We’ve fallen below what we call a sweet spot,” Lynn Helms, the head of the Department of Mineral Resources, said earlier this month. While producers can break even at just below $40 a barrel in most places, the Bakken needs prices in the $80-$85 range to attract capital from other shale areas.
“There is a concern there and that’s going to impact how they (operators) bring these wells on and how hard they produce them when they bring them on,” Helms said.
The International Energy Agency said this month shale should propel the United States to become the world’s top oil producer by 2015. Other analysts are increasingly bullish, projecting growth to 2020 and beyond as output defies doomsday predictions.
Company executives and analysts cited several mitigating factors cushioning the blow of lower prices.
In the past year, companies such as Continental, Whiting and Hess have sharply reduced costs through multi-well pad drilling, whereby several horizontal wells running in various directions are drilled from the same spot, reducing the time and equipment required to drill a single well.
Costs have fallen to around $7 million to $8.5 million per well, according to their statements, from an average of $9.5 million last year, according to IHS estimates.
And they continue to innovate, as lower costs provide more flexibility to try new ways to pump more oil for less money.
For example, Whiting said it had boosted improved initial production (IP) rates from wells from 587 bpd to 1,290 bpd by using a cemented “plug and perf” method prior to fracturing, rather than a “sliding sleeves” system.
Both ways refer to how a well is prepared before fracturing takes place, with the sliding sleeves being opened within the well for fracturing while the second way involves perforations made through the well to allow fracking liquids to be blasted into the reservoir at stages that are then plugged.
On average, peak month production from the Bakken has risen on average to 465 bpd per well in the first half of 2013 from 450 bpd in the second half of 2012, IHS estimates.
“They’re spending less so they can experiment more,” said Sven Del Pozzo, analyst with IHS said.
Bakken observers are also noticing operators’ increasing interest in “stacked plays”, meaning newly tapped or as yet untapped reservoirs lying underneath or above the three Bakken layers, the most well-known being the Three Forks formation.
Continental has been most vocal about the development of Three Forks, a formation of six depth levels. In its Antelope field, saddling the Mountrail, Williams and McKenzie counties, it will drill 350 wells targeting three Three Fork layers.
In addition, the smaller operators in the Bakken tend to actively hedge their future production, providing a cushion against any short-term drop in prices.
“Generally speaking the smaller the player, the more they’ll require to hedge ahead of time because (of) bank lending agreements,” Macquarie Capital analyst Vikas Dwivedi said.
For example, Kodiak Oil and Gas Corp KOG.N has hedged about half of its 2014 production at about $93 per barrel, far above current prices. Executives said they expect to add to the hedging position going into the new year.
With savings, improved production rates and hedging, the break-even point is still a way off by most accounts.
But formulating a break-even price is no simple matter and analysts differ in their calculations as the more than 100 operators in the Bakken have different costs, access to acreage of varying quality and distinct success rates in producing oil.
“We’ve seen tremendous variability in cost and well performance between operators as each tests different methods of well completion,” said Jonathan Garrett, analyst at Wood Mackenzie. Among the factors that can affect costs: lateral length, stage count, proppant volume and type, fluid volume and type, sleeves versus plug-and-perf.
Wood Mackenzie has an overall Bakken break-even price of $62 a barrel at current well costs, Garrett said. But for high-quality parts of the formation such as the Parshall and Sanish fields, that number goes down to the $38-$40 range.
North Dakota’s Department of Mineral Resources bases its break-even estimates on a 10 percent return on investment after tax and royalties, it said. Statewide, that price is $36 and for the four top Bakken oil producing counties it is $40 for Williams, $37 for Mountrail, $26 for McKenzie and $31 for Dunn.
It is equally difficult to pin down exactly how much money producers are making on each barrel they pump.
Prices at the Clearbrook, a junction for pipelines heading to the Midwest and Gulf Coast, offer a rough gauge, but do not always reflect producers’ financial reality.
Some can fetch $10 a barrel more by shipping it by rail, a costlier mode of transportation but one that avoids the glut at Clearbrook and delivers oil to premium markets on the East and West coasts, where crude prices tend to be based on the Brent benchmark, some $25 a barrel dearer at current prices.
Over 60 percent of Bakken crude, some 560,000 bpd, is shipped by rail. While narrowing U.S. crude spreads have made such trades less profitable in recent months, producers can still get a higher price by simply avoiding Clearbrook.
“Railing it out last year actually made money. This year, you’re not really covering the cost of railing, you’re just getting it away from the low pricing point at Clearbrook,” Del Pozzo said.
Reporting by Sabina Zawadzki, Jeanine Prezioso, Selam Gebrekidan and Ernest Scheyder; Editing by Jonathan Leff and David Gregorio