Bryan Sheffield, a third-generation oil wildcatter in Texas’s Permian Basin, knows what he’ll do if crude drops to $80 a barrel: shut down half his drilling rigs and go on a takeover hunt for weaker rivals.
Sheffield is among producers who’ve together invested $150 billion in the Permian since 2010 seeking their piece of an oil trove estimated to be worth as much #$%$ trillion. As the money pours in, risks are mounting of a bust as analysts including Marshall Adkins of Raymond James & Associates Inc. forecast crude is heading down to $70 a barrel next year, a price that would slow drilling in the most expensive U.S. shale formation.
While traditional wells have been drilled in the Permian since the 1920s, producers have become giddy over the potential of the region’s vast overlapping layers of oil-soaked shale rock. Pioneer Natural Resources Co. (PXD) estimated the remaining yield at the equivalent of 50 billion barrels, more than any field on Earth except Saudi Arabia’s Ghawar. The varied geology, though, makes it more costly to explore and develop.
“That’s the double-edged sword,” said Benjamin Shattuck, an analyst at Wood Mackenzie Ltd. in Houston. Multiple oil zones layered one atop another provide ample potential for riches, “but you also have to be a knowledgeable and good operator in order to drill economic wells out there.”
If oil drops another 18 percent to $80 a barrel, wells in some parts of the Permian that sprawls beneath Texas and New Mexico will become money-losers, said Tim Rezvan, an analyst at Sterne Agee & Leach Inc. in New York.
Energy producers on average need oil prices around $96 a barrel to break even on wells drilled in Permian layers known as the Cline Shale and the Northern Mississippian Lime, according to Mike Kelly, an analyst at Global Hunter Securities LLC. That compares to average break-even prices of around $78 a barrel in the Eagle Ford Shale a few hundred miles east of the Permian, and $84 in the Bakken of North Dakota.
It's just the state of denial he is (permanently) in. If Sandforbrains had posted anything about NGL hedges he would have agreed with him 100%. Note he never did answer re: EPD NGL hedges.
His selective interpretations are amusing.
Linn's acquisition won't affect 3rd quarter numbers since it wasn't scheduled to be closed until the 4th. Big oil prices won't help either as Linn is 100% hedged at a fixed price for all their current production well below those prices.
As the physical supply of NGLs has grown, the market for NGL derivatives has been gaining increasing liquidity, say market participants, allowing companies to hedge their risk more effectively. This represents a change from just a few years ago, when the instruments available for such firms were limited. Back then, there was a relatively small market for over-the-counter products, along with a single propane futures contract listed on the New York Mercantile Exchange. This meant many producers turned to proxy hedges using contracts linked to West Texas Intermediate crude oil. “Until about five years ago, that was pretty much the only avenue for hedgers,” says Dazzo. “But since 2008, a liquid market in each of the NGLs has emerged.”
In the OTC market, where the bulk of activity takes place. In three years, total open interest in all of the NGL contracts listed by the firm exploded, going from 5,461 contracts to 87,243 contracts, according to the firm. Atlanta-based ICE also clears trades linked to NGLs.
Denver-based DCP Midstream is among the firms that have changed their strategy in light of the recent moves. The company produces more than 400,000 barrels of NGLs per day, making it the largest NGL producer in the US. “The position that we hedge in NGLs has doubled over the last four to five years,” says Sean O’Brien, senior vice-president and chief financial officer at DCP Midstream. “We have grown significantly, so our need for hedging has increased."
Several years ago, the company could only hedge one to three months forward, but now it is able to hedge as far out as 12 months.. Consequently, the firm responded to the shake-up in price relationships by exiting its older crude oil positions and entering into new NGL swaps.
Until recently, there have been hardly any consumers of NGLs, such as plastic or chemical companies, hedging their NGL input costs but traders are seeing an increased interest among some of these counterparties to try to lock in a price.
" I like to roll my own numbers because frankly Linn is a bit aggressive with their "adjustments.""
"So if there are differences between my numbers and the S-4, it's probably because I derived mine independently."
Now, you may agree with his "numbers" but nothing that the SEC has done will change Linn's whatever it's calling DCF. At least that's what all the pumpers claim.
But your are saying that due to "SEC changes", Linn will be able to report higher cash flows, and thus better DCF coverage.
Not due to improved productivity, lower costs, higher NGL prices.
If you look into how many LINE/LNCO institutional investors have sold in the third quarter, you'd see that is already occurring, and that was long before the Berry 10-Q.
Given that Mr. Shih used the fourth amended S-4, and the fifth amended one changes the verbiage that Mr. Shih depended on, I'm not so sure what he wrote is still pertinent.
One would have to go through the changes in the latest S-4 to know if what he postulates still holds.
I thought Harold Hamm was your (and SOBs) Guru? Now you are dissing his opinions?
I guess you are the only one with all the answers.
Oil executive Harold Hamm, who made billions tapping the vast Bakken oil field in North Dakota before other companies saw the potential, sounded a pessimistic tone about whether the industry will develop California's Monterey Shale formation, which is estimated to have possibly five times more oil.
"It's just been tough to break the code on how to get that," said Hamm, founder and CEO of Continental Resources, an independent oil company with the largest footprint in the Bakken oil fields in Western North Dakota. "Everybody thought they could and it hasn't worked out."
He added that the field, which is located in the San Joaquin Valley in central California, has not yet matured to a form that companies could develop with today's technologies.
Speaking at a dinner Wednesday night in Washington with media reporters and other independent-petroleum executives, Hamm said his company had considered pursuing the Monterey formation.
"We went there and thought it might have a lot of potential," Hamm said. "I'd be out there, but I just can't do anything different than some of the people who have already been there and made that attempt."
The oil industry's potential pursuit of the Monterey shale formation has triggered an intense debate over hydraulic fracturing, or fracking, in California, a drilling technique that's helped unlock vast reserves of oil and natural gas around the country, including in North Dakota. But it's controversial for the environmental risks associated with it, including water contamination.
Called a "pioneer" by Interior Secretary Sally Jewell this summer for his early insight into the oil industry's potential in North Dakota, Hamm's glum outlook for the Monterey doesn't bode well for producers looking to tap into it.
"I don't see—" Hamm stopped mid-sentence and recast what he said: "It's yet to be seen…It might have a lot of potential, but there are reasons why it's not being produced."