WTI Vs. LLS: A Major Shift In The U.S. Oil Boom

For more than a century, the global oil and natural gas supply picture changed only a decade at a time.

In the past half-decade, however, the picture has changed with startling speed. That has been particularly true in America.

New technologies opened regional production in areas including North Dakota's Bakken Shale and Texas' Eagle Ford basin.

It reinvigorated aging fields, such as Texas' Permian basin.

Surging production from all of those territories has upended supply routes and forecasts.

Existing pipelines were suddenly in the wrong places.

Piecemeal construction of new lines, linking markets to bottled-up supplies, continually alters the pricing landscape. Railroads and barges -- much more pricey per barrel than pipelines -- are hustling to patch together the gaps.

The result has been a shift in long-standing paradigms that have traditionally guided oil buyers, gasoline pricing and energy industry investors.

"One of the secular challenges confronting investors right now is what to make of this oil pricing," said Bill Herbert, managing director with Simmons International.

Differences in regional oil prices are critical. They determine profits for the producers and refiners in those regions. High oil prices are good for oil producers, bad for refiners. The opposite is true when prices drop.

Historically, regional prices have remained fairly similar in America. International prices traditionally cued off of the U.S. light sweet benchmark known as West Texas Intermediate, or WTI.

But that has changed dramatically.

The Cushing Glut

Refiners in the Midwest have enjoyed a price advantage since about 2011. That's when supplies began to swell at Cushing, Okla., the storage complex and pipeline hub where the WTI benchmark price is pegged.

U.S. shale production and tar sands oil gushing into Cushing from Canada held down WTI prices.

International supplies were comparatively tight, so Europe's Brent crude benchmark rose from its traditional, second-place status to a premium vs. WTI.

Prices for Louisiana Light Sweet crude, priced at the U.S. Gulf Coast, also rose. The LLS benchmark is linked to Brent prices, largely due to imports shipped into the Gulf Coast market.

Gulf refiners therefore held a relative disadvantage. And producers in the Gulf of Mexico and in regions including much of Texas' Eagle Ford shale were paid a premium vs. WTI and Bakken crude.

Then there's a Midland, Texas, WTI benchmark that reflects prices for oil coming largely out of the Permian basin.

Since the middle of last year, that picture has substantially changed too.

Glut Migrates To The Coast

The recent startup of several high-capacity pipelines from Cushing to the Gulf Coast has once again altered the picture.

The Cushing storage hub has a total capacity estimated at 80 million barrels. New pipelines are sucking oil away from that hub, decreasing supplies in 14 of the past 15 weeks.

Supplies there have dwindled from more than 40 million barrels at the start of the year to below 25 million barrels.

Industry experts say inventories must remain near or above 20 million barrels in order to assure the ability to deliver contracted supplies to refiners as well as on futures contracts.

Supplies along the Gulf's energy complex, meanwhile, have soared. Stockpiles there rose from around 150 million barrels at the start of the year to more than 215 million barrels.

"People are beginning to get concerned," Herbert said, regarding the uncontrolled rate of rising inventories and the difference between the two regions.

Brent and WTI prices rose to three-week highs Wednesday, despite data from the Energy Information Administration showing U.S supplies continued to increase.

Supply also continued shifting from Cushing to the Gulf, and gasoline demand increased for the first time in four weeks.

The LLS benchmark continued to hover about $1.90 above WTI, according to energy analyst Phil Flynn with Price Futures Group. That was well below Brent's $8 premium, but not reflective of the swelling supplies in the Gulf.

"Traditionally, light Louisiana competes with Brent," Flynn said. "If we started to export more U.S. crude, that would really bring it down."

Increasingly Complex Picture

As a result of the inventory shift, and tightening supplies in Cushing, "any company with refining capacity around or near Cushing would expect to pay more" for its oil, said Oppenheimer analyst Fadel Gheit.

Benchmark prices haven't started to fully reflect a Gulf glut. But Midwest refinersMarathon Petroleum ( MPC ),HollyFrontier ( HFC ) andBuckeye Partner s ( BPL ) reported Q1 earnings misses. Marathon also has Gulf Coast refineries.

The Gulf Coast's largest refiners, meanwhile, began reporting stronger earnings surprises.

Exxon Mobil ( XOM ), which operates refineries with capacities totaling 1.4 million barrels per day along the Gulf, topped views by 11%.

Royal Dutch Shell (RDSA), which with Saudi Aramco owns the 600,000-bpd Motiva facility in Port Arthur, Texas, cleared analyst Q1 earnings estimates by 48%.

Another layer of complexity arises in the various grades of crude being supplied.

Most crude being produced in the U.S. is high-grade light sweet crude.

That creates challenges because a large portion of U.S. refineries are built to process heavy crude from Canada or imported from Mexico or Venezuela.

As a result, "we've already basically crowded out all of the light sweet imports into this country," Herbert said. "We're probably going to need to displace medium-grade crudes going forward."

That could be a more difficult transition, he says, because many of the midgrade refineries -- such as Motiva -- have close ties to the importers of the midgrade crude.

What's more, a number of Midwest refiners have converted their facilities to be able to process heavy sour crude.

Heavy crude coming in from Canada has traditionally traded at a 20% discount to WTI, says Earl Sweet, senior economist with BMO Nesbitt Burns.

During the Cushing glut, that discount at times widened to nearly 50%.

"There was nowhere for that oil to go," Sweet said.

That has changed with an increase in heavy crude processing capacity among Midwest refiners. Most notably,BP 's ( BP ) 413,000-bpd Whiting refinery, which was upgraded last year, raising heavy sour crude to as much as 80% of its raw input vs. only 20% before the retrofit.

Husky Energy is spending $300 million to upgrade its Lima, Ohio, plant to handle more heavy crude.

"So all of that heavy oil growth taking place in Canada doesn't have to get all the way down to the Gulf Coast," Sweet said, "There is increased demand for it at midcontinent."

The elephant in the room throughout the oil supply conversation is the question of lifting the U.S. oil export ban. Groups like the American Petroleum Institute are lobbying hard for easing of the 40-year-old rule.

Energy Department Secretary Ernest Moniz said Tuesday that "the issue of crude oil exports is under consideration."

A key factor driving the discussion: "The nature of the oil we're producing may not be well-matched to our current refinery capacity," said Moniz.

Long View: Refineries Are Fine

The longer-term scenario suggests, at some point, Gulf Coast storage will reach capacity.

At that point, at least some pipelines between Cushing and the Gulf are likely to be idled.

Cushing inventories will begin to recover. As U.S. supplies increase, WTI and other benchmark prices could fall.

And the pending startup of additional pipeline capacity from Cushing to the Gulf suggests the situation is about to become even more exaggerated.

The outlook for refiners?

"The refiners couldn't have it better," Gheit said.

They like to see a glut of oil, he says, because it creates a buyer's market in which refiners pay less for oil.

"That's why the refiners are opposed to lifting the oil export ban," he said.

In addition, and for the foreseeable future, domestic refiners have the advantage of a natural gas glut.

That means, Gheit said, the group overall has "an 80% advantage in operating costs vs. the refineries in Europe."

That could change if rules regarding oil exports change, but the important factor to remember is -- until further notice -- the industry is likely to remain in a state of rapid change.

"We are going through a historic change, from being basically dependent on imports to being a major exporter," Flynn said. "And there are opportunities along the way."

The views and opinions expressed herein are the views and opinions of the author and do not necessarily reflect those of Nasdaq, Inc.

The views and opinions expressed herein are the views and opinions of the author and do not necessarily reflect those of Nasdaq, Inc.

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