Chris Keene: “(And) you have the Delaware Basin sitting out there, saying, ‘Wait a minute. What about me?’”

As oil flowing from Texas and New Mexico has grown to more than 3 million barrels a day, railers, truckers, pipeliners and producers are quickly adding infrastructure to get it to market. But new production from both the Permian is increasingly competing for refining capacity.

“We’re going to need to look at how we get more (Permian) barrels to Cushing or we’re going to look at the West Coast,” Jarrett Vick, president of oil-trucking operator Permian Transport & Trading, said in DUG Permian 2014 post-presentation Q&A session in Fort Worth in May. “I think the markets will determine that for us in the near future.”

Chris Keene, president and chief executive officer of Bakken rail operator Rangeland Energy LLC, said unit-train take-away is crucial in the western, Delaware Basin portion of the Permian Basin, which is more pipeline constrained than the eastern, Midland Basin portion.

“When did we realize it? Probably about a year ago, just in looking at the trends in production as well as in pipe capacity,” he said. Rangeland is building a unit-train loading facility near Loving, New Mexico, in the Delaware Basin, hauling oil out to Cushing and the Gulf Coast, while hauling proppant in.

“Rail has made crude oil a nationally traded commodity,” he said. “You seek out your highest-value market. Our markets are the East Coast, where you’re competing with Brent, and the West Coast, where you’re competing with ANS (Alaska North Slope oil) or foreign cargos.”

Texas’ production just four years ago was 1.13 million barrels a day; the U.S. Energy Information Administration estimates that, in March, it was 2.97 million a day. Meanwhile, New Mexico’s production has grown in the past four years from 179,000 barrels a day to 313,000.

New production from the Delaware Basin, which straddles the New Mexico/Texas border, may struggle for a market in the shadow of new Midland Basin, Eagle Ford and East Texas supply, Keene said. “If I were to have a crystal ball and look at it, I would say, ‘Okay, as you see more of this light, sweet production coming off the Eagle Ford and…in East Texas and in the Bakken, initially there is this bubble that is built. And as this new pipeline capacity gets built out of the Permian around Midland and Colorado City…you have the Delaware Basin sitting out there, saying, ‘Wait a minute. What about me?’

“So price-impact (risk) there is No. 1. And now you have the rail option. We’ve provided that.”

Darrel Koo, senior associate, energy research, for ITG Inc., said in an economics-panel Q&A session that he expects price pressure in the Gulf Coast and other U.S. oil markets, resulting in a widening differential among them, thus producers laying down rigs in the future. “There is probably a bit more room to go before we see very severe discounts.”

Raphael Hudson, director, upstream research, for Hart Energy, said, “There is a little bit of spare capacity in terms of the refining capability, even though there is a mix-match in terms of the crude quality.” New U.S. oil production is light-gravity while most U.S. refining capacity is weighted to processing heavy oil of less than 38 degrees. From the Eagle Ford, in particular, a great deal of production is super-light, 60-plus-degree-gravity condensate.

Scott Sheffield, chairman and chief executive officer of Pioneer Natural Resources Co. and who presented in the conference as well, estimates some 800,000 barrels—or roughly 10%—of current, daily, U.S. oil production is condensate.

Hudson said, “One possible relief valve would be condensate splitters. When you split the condensate—and a lot of this light oil would qualify as condensate—you are no longer dealing with an unrefined product so, therefore, it is exportable. That could relieve some pressure in the short term.”

Benjamin Shattuck, upstream analyst, Lower 48, for Wood Mackenzie, said some Permian operators will be well positioned to deal with a lower oil price. “Midland has been through boom/bust periods. Operators have not forgotten that…Operators now…are dialing down lease-operating expenses for that reason and trying to buy mineral rights to position themselves in a lower oil-price environment.”

Permian oil is mostly 40 degrees in gravity, Koo noted, “with exception, such as the western Delaware Basin, where the liquids are lighter. As Cimarex (Energy Co.) has indicated, they are probably 50- to 55-degree API, but that is a specific part of the basin. The rest is roughly 40 to 45 degrees.”

Koo said he and his ITG colleagues are “kind of in a $90 oil camp with the preface that there will be volatility, certainly in local hubs in the Lower 48. There is going to be some downside pressure in the Gulf Coast in the next year or so.”

Joel Castello, reserves and acquisitions manager, for Endeavor Energy Resources LP, which operates in both the Midland and Delaware basins, said, in a private-operator Q&A session, “I read the same things you all read…The world is what it is. You could have a global recession or wars that change the price…There are all kinds of risks out there.”

Kirk Blackim, director, business development, gathering and processing, for Crestwood Midstream Partners LP, said, “One of the things we’ve seen in the Marcellus area is, through the use of condensate stabilizers, we are driving off a lot of the light end so it ends up in the NGL products.

“But, given the current state of the refining industry and the ability to handle the heavier crudes and less light crude, there is only so much of that that the industry can tolerate.”

John Harpole, president of advisory firm Mercator Energy LLC, said a fellow markets analyst looked at the slate for the 138 oil refineries in North America to see if merely blending light oil with heavy oil will resolve the gridlock. “The entity that comes up on the short stick on that one is light, sweet crude,” he said. “We simply can’t blend enough.”

Rail operator Keene noted that condensate is “darn near an NGL (natural gas liquid) anyway.” The U.S. Commerce Department is considering an industry proposal that condensate no longer be defined as crude oil, of which the U.S. forbids meaningful export.

People are looking at potentially exporting condensate,” Keene noted. “And, people are looking at ‘Do you just have to split it and export the products?’ Do you split it (where it is being produced) and rail it out? Or do you rail the condensate down to a port at the Gulf Coast, split it there and export the products?”

Meanwhile, oil-quality concerns have developed among refiners who receive shipments via rail, Harpole said.

Keene concurred: “Crude quality is becoming the issue.” He worked, previously, for a refiner in its midstream business unit. “Refiners do not like condensate. You refine crudes for refining value. Eventually these crude streams get saturated.

“As a producer, you can no longer blend this condensate into the stream. In some cases, you try to dump it in. It finds its way into a truck or into a rail car and, ultimately, a ‘it hits the fan’ kind of thing…A lot of this condensate is going to be looking for a home…and purity of product continues to be important.”

Truck operator Vick said the company has to know exactly the gravity of what it puts into its trucks, since the product is then taken to a pipeline, which has rigid quality specifications. “We have to look at that because of the pipeline specs,” he said. “The pipelines are starting to penalize.”

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.