Refiners Adapting To Shale Shock

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When the largest refinery on the East Coast, a facility snugged up to the Schuylkill River in South Philadelphia, sold in July, it immediately became a symbol of the rapidly changing refining trade.

The sale ended Sunoco's tenure as a refiner, which had lasted more than a century.

The facility is being reorganized by a Carlyle Group (CG)-led partnership to take advantage of low-priced gas flowing out of the Marcellus Shale fields. Its rail terminal, designed for high-speed offloading, aims to gulp increasing shipments of cheap oil from the Bakken Shale in the Midwest.

The aggressive repositioning is only one snapshot of a thin-margin industry which, after decades of baby-step progress, finds itself suddenly restructuring at a gallop.

Refiners across the industry have seen recent profits either crumple or soar. In addition to Sunoco's final bow, BP (BP) downsized its U.S. refining operations. It sold two of the largest U.S. refineries at bargain rates while investing $4 billion to upgrade its Whiting, Ind., unit.

The central theme driving nearly all of that change, says John Felmy, chief economist with the American Petroleum Institute, is "the relative cost of (refiners') crude inputs vs. their competition.

In a nutshell, the rise of shale oil production has meant that Midwest refiners pay less for crude, giving them a profit advantage relative to their counterparts on the East and West coasts.

As a result, midcontinent refiners have posted some of the industry's strongest stock-price moves this year.

Western Refining (WNR) is up 89%, CVR Energy (CVI) up 112% and HollyFrontier (HFC) advanced 82% year-to-date through Friday. Those moves are helping to hold refiners in the top 20 rankings among the 197 industry groups tracked by IBD.

The questions now: Will the group's earnings hold up? Will the price differential between coastal and interior crudes remain? And how will refiners adapt

Shale Shock The Bakken Shale is a geological region spread beneath North Dakota, Montana and Saskatchewan. The name rose into common use as oil producers began applying high-pressure fracturing and horizontal-drilling techniques first used to open up natural gas deposits across the South and Northeast.

These techniques lifted North Dakota's oil production from less than 100,000 barrels per day in 2005 to 729,000 barrels per day in September.

Chris Micsak, senior energy analyst with energy researcher Bentek, estimates that daily production will reach 748,000 barrels in November, with an additional 81,000 barrels coming from the Bakken's Montana side. And the numbers just keep growing, says Bob Levin, a managing director of commodities research for CME Group.

"If you tend to be conservative in the way you express yourself, you consistently underestimate the production levels and flows. They are surprisingly high and growing," Levin said.

The effects of that homespun oil boom are rippling around the globe.

Historically, West Texas Intermediate (WTI) crude, priced at the pipeline hub in Cushing, Okla., trended about $2 above Brent crude, produced in the U.K.'s North Sea. The price spread was good for domestic oil producers, but costly for refiners.

The spread fluctuated, but WTI always, eventually returned to its premium. That began changing in 2010, when U.S. shale oil production ramped up. New oil supply flowed from the Bakken and joined incoming tar sands crude imports traveling south from Canada.

Pipelines out of the Midwest were limited, geared to traditional volumes. In fairly short order, the tank farms at the Cushing storage hub were overwhelmed with supply. WTI prices trended lower and have traded recently around $86 a barrel. Brent has hovered near $109.

That difference imposes a significant price disadvantage upon coastal refiners, helping to explain moves like the closing of the South Philadelphia refinery.

The South Rises But Gulf Coast refiners, which account for nearly half of all U.S. refining capacity, are gradually being exempted from the coastal premium.

The Seaway pipeline, a joint venture owned by Enterprise Product Partners (EPD) and Enbridge (ENB), reversed its original course and began moving crude from Cushing to Freeport, Texas, just south of Houston.

It made its first deliveries in June and is expected to ramp capacity to 400,000 barrels early in 2013. A parallel line, slated for completion in 2014, aims to raise the flow to 850,000 barrels.

TransCanada's (TRP) Keystone XL line, a political football farther north, is already approved running south from Cushing to Nederland, Texas, near Port Arthur.

In addition, production from other shale plays has also ramped up. Production in the Eagle Ford fields in South Texas has increased, with much of that supply flowing toward Gulf refineries.

Combined, the new supplies will place downward pressure on the Light Louisiana Sweet benchmark used as a gauge for Gulf Coast prices.

Eventually, it could also affect Brent prices. Energy Information Administration data show foreign imports into the Gulf have dropped by half since 2010.

The MLP Factor Independent refiners are gathering an increasing share of U.S. production capacity, even though large integrated plays like Exxon Mobil (XOM) and Chevron (CVX) still own the country's largest refineries.

But the sale of BP's refinery in Carson, Calif., to Tesoro (TSO), as well as the sale of a Texas facility to Marathon Oil (MRO), boosted independent market share.

In addition, Marathon had already divided much of its refining and pipeline assets into the independent Marathon Petroleum (MPC) in 2010. In May, ConocoPhillips (COP) spun off Phillips 66 (PSX) as its stand-alone refining play.

The sector is also rapidly restructuring as it rolls pipeline assets into master limited partnerships. MLPs make competitive investment vehicles because they pay out whatever cash flow is not directly used in company operations. In addition, pipelines tend to be noncyclical, making the MLP stock prices theoretically less volatile.

The primary owners of the assets used to create the MLP generally incorporate a managing partnership. This governs pipeline activities and typically receives a large share of the MLP's payout.

Refineries are occasionally shifted into MLP settings: Northern Tier (NTI) and NuStar (NS) are refining MLPs.

Outlook The refining sector saw a flurry of downgrades in mid-September, led by analysts at Citi and Credit Suisse. The analysts reasoned the industry had worked through the benefit of a rash of shutdowns, and that the Bakken's rising rail shipments were eating into the spread between domestic and imported crudes.

But Credit Suisse analyst Edwin Westlake reversed course in late October, based on the potential for MLP-related valuation improvements. In an Oct. 26 report, Westlake upgraded Phillips 66, Delek U.S. Holdings (DK) and Marathon Petroleum — all refiners with a midcontinent focus — to outperform from market weight, and raised their price targets.

Two weeks earlier, Goldman Sachs' lead energy analyst Arjun Murti had upgraded his view on the refining sector to attractive, raising Western Refining to buy from hold and reiterating buy ratings on HollyFrontier, Marathon Petroleum and Northern Tier.

Murti put the general trading range for Brent crude between $100 and $110 per barrel through 2015. He widened his projected spread between Brent and WTI prices to $7 from $5 per barrel.

In addition, Murti noted that rising rail shipments from the Bakken to the East and West coasts could drive U.S. domestic prices even further below the international benchmark, pointing to "long-term crude oil discounts of $7-$12 (per barrel)."

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