Analysis - Before the flood: Preview of a U.S. market drowning in oil


By Jonathan Leff and Matthew Robinson

NEW YORK (Reuters) - The U.S. oil market is getting its first real taste of a remarkable phenomenon that may soon become a permanent reality: an excess of light sweet crude oil.

With a swath of refineries shut down for routine seasonal maintenance this month, the unyielding gusher of crude from U.S. shale wells and Canadian oil sands plants has temporarily overtaken demand from refiners, say analysts and traders.

Parts of the market have faced such gluts before, of course. The storage hub in Cushing, Oklahoma, was filled nearly to capacity at times over the past two years, and Canadian and North Dakota producers have felt the price pain of surplus supply. More recently the Houston area has been swamped by a deluge of Eagle Ford shale.

But for the first time since the onset of the shale revolution, the whole of North America seems to be in sync, as prices signal a market inundated with excess oil. Storage tanks across the nation are backing up, particularly along the Gulf Coast, a region perennially short of crude.

Price differentials from California to New Jersey and North Dakota to Texas have fallen in unison to multiyear lows, the result of relentless growth in shale oil production as well as three years of breakneck investment in pipelines and rail terminals.

"You now don't have those dislocations because you have a much more integrated system - crude can move in multiple means to different areas with far more flexibility," said Daniel Sternoff, senior managing director at Medley Global Advisors.

To be sure, the current excess seems certain to be temporary, most analysts agree. With some 1 million barrels per day (bpd) of capacity set to return from maintenance next month, prices should perk up as refiners bring back plants, many of them exporting fuel to Latin America, Europe and Africa.

Yet the swift downturn in key price differentials and crude oil spreads this month offers a preview of what's in store for U.S. markets that have been repeatedly roiled by the shale boom - crude oil straining at the U.S. borders, unable to be easily absorbed by refiners or legally exported by producers.

The addition of new pipeline capacity coming onstream at the end of this year and next should create a smooth, uninterrupted flow of oil from Canada, North Dakota and Texas to Gulf Coast refiners, breaking down the last major logistical hurdles of recent years.

Even then, it will take time to reach a genuine glut.

First, as prices tumble, shale oil will be cheap enough to ship to refiners on the U.S. and Canadian east coasts, which together still import some 1 million bpd of oil. As prices fall further, savvy Gulf refiners are likely to find ways to blend the overabundant light sweet shale with heavier grades to replace more medium-density crude.

"(The Gulf Coast) is not broken in the way that things were over in Cushing in 2012. There are many more options. It's a much bigger system," said Jan Stuart, head of Global Energy Research of Credit Suisse.

But within a few years, perhaps by 2015, the logistical and market bottlenecks will yield to a regulatory one: a decades-old U.S. law that, with the exception of Canada, effectively bars exports of crude.


The evidence is tucked away in opaque prices and price premiums and discounts that have slid across the board.

For once the signals are not confined to the closely watched spread between U.S. futures and European Brent, which has been dismissed in recent years as a flawed indicator, distorted by the lack of pipelines pointed south.

The spread has ballooned by $5 in just days, briefly reaching a six-month low of over $13 a barrel on October 23, still far from the record of $28 hit in 2011. Traders have said pipeline maintenance in Texas may have exacerbated the problem, forcing more oil up into Cushing rather than off to the Gulf Coast.

This time, other regional crudes are under pressure.

Crude produced in North Dakota's Bakken region has plunged to lows of $14 a barrel below U.S. oil futures in October after fetching premiums as recently as June owing to the surge in production. North Dakota's output is expected to continue to grow, topping 1 million bpd by the end of the year as part of the second-biggest oil boom in history.

The momentary glut caused by the refinery work has even overwhelmed one of the last areas of relative strength for the crude oil market. The St. James trading hub in Louisiana has remained a bastion because it is ill-served by pipelines from Cushing and Houston, where crude is abundant.

Light Louisiana Sweet is barely $1 higher than U.S. crude futures, often called West Texas Intermediate (WTI), the lowest since 2010 after hitting a record $10 discount to Brent this week, according to Reuters data.

Oil priced at St. James is now so cheap that BP is sending it to Canada, shipping data show. While cargo shipments from Texas to Irving's refinery in St. John's, Newfoundland, have become relatively common this year, oil shipments from the Port of Louisiana are rare.

Even the premium for Alaska North Slope on the West Coast, a market that typically bears little relation to the domestic U.S. market, has been affected. The crude has hit discounts of more than $7 a barrel to Brent for the first time since late 2012.

"If continued, this trend would suggest that ANS prices are being driven more by U.S. domestic crude rather than by competition from imports. That would be a startling development," since only a limited amount of shale crude is moving West, RBN Energy analyst Rusty Braziel wrote this week.

He suggested the downturn was related to pressure on heavier crudes in the Gulf Coast, which have also weakened.


Once the congestion of the U.S. system eases and crude can flow nimbly to the major regional markets, it will no longer be so surprising for domestic crude prices to start moving more in step, rather than separately.

The market has already sorted out some of the problems associated with delivering crude from regions like the Bakken in North Dakota, far away from any refining centers or transport networks. Rail terminals have sprung up, new pipelines laid or reversed, and barges pressed into service carrying sweet crude from Corpus Christi, Texas, to Louisiana.

"There's a huge amount of infrastructure in the Gulf and it will get better integrated as time goes on," said Eric Lee, commodities analyst at Citibank.

Access to domestic crude along the Gulf Coast increased sharply this year as new pipeline capacity connected the region to Cushing and to West Texas oil fields.

Shipping oil by rail has also opened up new options for trading domestic crude, with 70,000-barrel unit trains and smaller shipments now accounting for about a tenth of all domestic U.S. oil transport - versus zero three years ago.

Crude-by-rail shipments reached 862,000 bpd in the second quarter, more than double a year before. In North Dakota alone, over two-thirds of the state's 910,000 bpd from the Bakken shale is shipped on rail cars. A fifth of that goes to a refinery in Philadelphia, officials have said.


The current weakness is almost certain to be temporary.

Gulf Coast refiners who were running their plants at a record 95 percent of capacity in July have cut back to near 87 percent, reducing demand for crude by some 770,000 bpd because of maintenance. But they are already starting to rev up again, drawing down swollen stocks and goosing prices.

While autumn refinery maintenance is a normal phenomenon, the impact of strong domestic oil production has deepened the market's reaction this year. During these lulls in the past, refiners could generally cut back on imports rather than domestic crude, pushing the effects of the slowdown overseas.

This time light sweet imports into the Gulf Coast have already dropped dramatically as local crude has displaced them, causing more of the market weakness in the domestic market.

Crude imports this year to the Gulf Coast from the four largest sweet crude suppliers in OPEC - Algeria, Angola, Libya and Nigeria - fell in July to just 78,000 bpd. Three years ago the four countries were shipping more than 1 million bpd.

The region will still import crude, certainly. Most refineries there were built to run on heavier, sour crude, and those barrels from Saudi Arabia and Mexico will keep flowing.


It is likely to be months if not a year or more before the Gulf Coast region is permanently sated with crude, according to Goldman Sachs, which last week laid out nine milestones on the march toward saturation, including:

* The startup of TransCanada's 700,000 bpd Cushing-to-Texas MarketLink pipeline by end-2013.

* The completion of Phase 2 of the 200,000 bpd Houston-to-Houma pipeline system, which will carry crude to Louisiana refiners by the end of this year.

* Startup of the Seaway II pipeline to take another 450,000 bpd of crude from Cushing to Texas in early 2014.

Beyond the Gulf, shippers are likely to push oil to the East Coast of Canada, which only this year has begun taking a growing volume of crude from Texas. Seaborne crude shipments to Canada from Texas and New York peaked at 75,000 bpd this summer, but dried to a trickle this autumn as the narrower Brent/WTI spread made European crude more competitive.

Once that market is inundated, shippers and rail operators will target the U.S. East Coast, a pricier option given the requirement to use U.S.-built and -crewed Jones Act tankers, of which there is a small and limited supply.

As the last remaining drips of imported sweet crude are choked off over the course of 2014, refiners will likely get creative, blending to work out the oversupply, according to analysts.

"Refiners are going to start figuring out how to blend this stuff with heavy to start backing out medium-level crudes," said Sternoff of Medley Global Advisors.

Credit Suisse expects U.S. oil will begin to compete with the Gulf's most hard-core heavy crude imports by 2017 or 2018.


Ultimately, however, the North American system will reach a point where it can't absorb any more light sweet barrels. Prices will come under mounting pressure as producers struggle to sell the marginal barrel. Either production will have to be slowed or U.S. laws will have to be changed to allow wide-scale oil exports, experts say.

The debate over amending the U.S. ban on exports, put in place after the Arab oil embargo, has yet to start in earnest in Washington. While gasoline and diesel is freely allowed to move to foreign markets, the issue of shipping American oil overseas is considered a political hot potato neither Democrats or Republicans are eager to handle.

For many experts, it's only a matter of time.

If the shale boom appears endangered by low prices, policymakers may be forced to confront a trade law that most would rather ignore, says Jason Bordoff, director of the Center on Global Energy Policy at Columbia University and a senior White House energy adviser until late last year.

"The fact is that this is coming, and the issue of crude exports will be getting even more attention by early next year."

(Additional reporting by Jeanine Prezioso; Editing by Prudence Crowther)

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