No Catastrophe … And That's the News

John Kingston, Global Director, Platts Oil

Regulations and hurricanes were expected to throw the market into turmoil. But despite some rising prices, the fallout didn't live up to the hype. The laws of supply and demand proved an effective regulator, and the oil industry showed incredible resiliency.

WHEN WE THINK BACK ON ENERGY COMPANIES and their people who have turned in outstanding accomplishments in the last year or so, maybe it's time to give a big round of applause to the oil markets of the last 16 months.

Those were the 16 months that were going to result in all sorts of calamities. We weren't going to have enough gasoline after hurricanes Katrina and Rita. The resulting loss of distillate supply in September and October from the storms was going to tighten up heating oil supplies for the winter. The removal this spring of MTBE from the U.S. gasoline supply was going to cause chaos. The switch to Ultra Low Sulfur Diesel was going to cause more turmoil. And so on. And so on. That doesn't even get into all the political upheaval that was going to impact supply.

Guess what? Didn't happen. None of it.

Yes, the price is high by historical standards, but it never did reach the inflation-adjusted peak of the early 1980s. The market of the past year and a third showed a few things, and they all generally confirmed what we learned in Economics 101.

First, when you have spare capacity to produce something, be it widgets or oil, and that cushion is only at about 2%, there's going to be upward pressure on the price of the widget...or the barrel.

Second, no matter how much investor interest is working to bid up the price of a commodity, supply and demand will eventually trump all.

Third, the next time you hear that a certain change in the market is going to result in all sorts of awful things happening, you might want to take a deep breath.

Oil markets have shown tremendous resiliency in the period. Battered by storms, ambushed by politically-driven shutdowns in Nigeria, thrown off track by corroded pipelines in Alaska, pushed upward by relentless Chinese demand growth—and the only people who had a tough time getting oil during all of that were a few customers on the Colonial Pipeline immediately after Katrina. That lasted just a few days.

There was one other group, however, which had trouble getting supply. In 2005, gasoline lines developed in China, thousands of miles from where they were supposed to be, after the back-to-back hurricanes in the U.S. A few gasoline lines developed in the southeast U.S., and lasted maybe a day or two immediately after Katrina.

The difference is the cause. Chinese refiners were squeezed between the rising cost of crude and government-capped wholesale and retail prices. The result was that state-owned companies that have been trying to be seen as equal to international majors reduced runs in response to weak margins created by government diktat. Despite that, they ended up posting horrendous financial results while their counterparts in free markets were benefiting from eye-popping margins. While China has taken steps to liberalize its markets, the fact remains that it will be difficult for a company like Sinopec Corp.—which is more of a pure refining play than a firm like PetroChina Co.—to be considered a world-class oil major if its exposure to refining margins is dictated largely by social policy rather than raw economics.

Contrast that failure—the simple inability to deliver product to customers who want it, because market forces were stopped by government edict—with the ways that the market did work.

Ethanol

This was going to be the disaster that took gasoline prices soaring. And for awhile, it looked like that might happen. With the U.S. federal government rule requiring an oxygenate in reformulated gasoline set to expire in early May, company lawyers took over. The message was simple: without the legal cover of the oxy rule, continued use of MTBE could result in legal setbacks as companies fight a large pile of lawsuits blaming the additive for a variety of ills. So even though MTBE was not banned by the federal government, the loss of the oxy rule proved the death knell for American consumption.

But when MTBE went out, it took a lot of octane with it. The only thing that could replace much of that octane was ethanol; there isn't enough supply of alternative octane blendstocks such as reformate to completely avoid using ethanol.

But the logistics of ethanol are vastly different from MTBE. Its blending properties are unique, and its transportation requires a completely separate system that requires ethanol to be injected into an unfinished gasoline blendstock—RBOB, or reformulated blendstock for oxygenate blending—far downstream. It had all the makings of a disaster.

And for awhile, it looked like that might occur. Ethanol, which has a natural premium to gasoline of 50 to 55 cents per gallon because of the combination of tax breaks and tariffs established to protect the U.S. industry, soared to more than a $2/gallon premium to gasoline in the Gulf Coast for a few days in late June; it had been at about 65 cents in early May, just as MTBE was disappearing from the gasoline pool. Spot shortages of gasoline were reported at wholesale distribution points, particularly in Dallas, where ethanol, for all intents and purposes, was a new product (Figure 1).

1. Gulf Coast Ethanol Over Gulf Coast Gasoline. Source: Platts

But just when it looked like all the doomsayers were going to be proven right, ethanol started to fall. Not just a little bit; it fell hard, to levels less than its natural spread. By mid-October, the spread to conventional was down to less than 40 cents, though the spread to RBOB, the building block for reformulated gasoline, was a little bit higher at 46 to 47 cents. The logistics were conquered, numerous new plants came on, and the spread overcame that barrier put up by the tariff. The market worked.

The ethanol market will always have a tough time operating unfettered, given the U.S. government's strong interest in directing an intended outcome. As a result, the spring's fears of an ethanol shortage were transformed into projections of a glut. The renewable fuels standard in the Omnibus Energy Bill, enacted in 2005, calls for a renewable fuels mandate of 7.5 billion gallons of consumption by 2012. That would be up from estimated 2006 consumption of around 4.5 billion gallons.

So the renewable fuels mandate and the end of MTBE consumption have combined to help drive a vigorous expansion of the U.S.'s ethanol capacity, actual and planned. Some estimates project U.S. capacity to produce ethanol, driven by a building boom in the nation's heartland, will rise to as much as 9 billion gallons by 2009, which is more than the mandate and exceeds all but the most ebullient projections of what consumption will be at that time.

But don't worry. The market will work. Government support notwithstanding, the combination of weak demand, strong steel prices, tight labor markets and possibly high corn prices—driven in part, of course, by soaring ethanol use—will dial back those plans considerably.

ULSD

There never was any question that U.S. refiners would be able to make the specification of 15 ppm sulfur required in Ultra Low Sulfur Diesel (ULSD). The problem always was that 15 was not going to be good enough, because as ULSD moved through product pipelines, its sulfur content would naturally rise as it came into contact with the residue of other higher-sulfur products, such as jet fuel or heating oil. The fear was that the resulting "contaminated" product would not pass the 15 ppm test.

With help from government rules that have been praised by some members of the industry, ULSD made its staggered debut in June with minor difficulties in some markets, particularly the Midwest. By mid-October, when the 2006 portion of the ULSD rule was to be fully implemented (ULSD will be completely in place in 2010), the spreads that ULSD was carrying over fellow distillates No. 2 oil and jet fuel, to say nothing of the less restrictive low-sulfur diesel, showed no signs of a tight market. The staggered nature of the introduction of those rules gave the industry a learning curve that it used to its advantage. Again, the predicted apocalypse did not occur, and this time, the way the federal government went about it was given credit for the smooth ride (Figure 2).

2. New York Harbor ULSD vs. No. 2 Oil. Source: Platts

One other factor: imports. Imports of diesel meeting the ULSD specification went as high as 280,000 b/d by the middle of September. It's difficult to say whether that number is high or low; the ULSD rules are a new phenomenon, and it will take time for a base number to develop that is considered "normal." But consider this: that mid-September peak of 280,000 b/d came as the U.S. was producing 2.55 million b/d of ULSD, so imports were about 11% of total production. A year earlier, with no ULSD rule in place, the U.S. produced 2.95 million b/d of low-sulfur diesel, defined as being between 15 and 500 ppm. Imports were a mere 77,000 b/d. So the market, through the action of arbitrage, moved to dump excess supply of ULSD from other parts of the world onto the U.S. market, helping to avoid the widely-predicted squeeze on supplies.

The ULSD conversion is not completely done. For example, there are rumblings that given some problematic cold-weather properties of the fuel, the market may be tested during the winter. Additionally, Lynn Westfall, chief economist at Tesoro Corp., told Platts that as heating oil gets put through pipelines in greater quantities this winter, sulfur contamination problems that have been averted so far may arise.

Crude

Over the last few years, you could have gotten a pretty good debate going on how much impact on price was being generated by the activity of hedge funds and other financial interests investing in crude and other petroleum products. Through late 2004, when the market was in backwardation with each successive month's price lower than the previous month, a fund could get out of the NYMEX front-month contract, roll to the next month and collect 30, 40, 50 cents per barrel…or more. The markets were rife with talk of $100 crude, as more funds poured money into the market.

The problem is that there was no way such a backwardation was going to last while crude stocks built. The slope of the curve correlates strongly with the level of inventories. U.S. crude stocks reported by the Energy Information Agency crossed the 300 million barrel mark in April 2004 and peaked at more than 345 million barrels in June of this year before sliding back to 330 million barrels in early October. Still, those numbers significantly exceed norms by any measure.

So it was no surprise then that the long backwardation toward the front of the curve was gone by the end of 2004, replaced by a steep contango that, in theory, should have deterred those funds from taking on length. Instead, the length kept being added…but it was added through purchases for delivery in 2008 and beyond, where backwardation still existed and the profit-eviscerating roll didn't need to get done. Yet as the price declined through the summer and early fall, down to the $60 level, so did the length, to the point where non-commercial long futures positions reported by the Commodity Futures Trading Commission—the group that consisted of hedge funds—had dropped to near net zero by mid-October.

The events of the past months, and the movement in those positions, gave significant support to the idea that fundamentals ultimately will triumph. First, the buildup in stocks created in part by high prices led to contango supplanting backwardation, pushing hedge funds to move their ownership of crude into the "out" months. That eased pressure on the front month. Secondly, as outright prices dropped, it didn't matter that the funds' positions were out that far; their mark-to-market still pointed down, margin calls needed to be made and the most recent data indicates they are fleeing the crude market.

In retrospect, it seems hard to believe the market feared that speculative money alone could drive prices to $100 when fundamentals were being weighed down by inventory.

It also seems hard to believe that consumers weren't going to react to high prices. International Energy Agency (IEA) figures clearly show that they did. By mid-2006, the IEA estimated that total world demand by year's end would average 84.7 million b/d for the 12 months. A year earlier, the IEA projected average 2006 demand at 85.3 million b/d. Anyone betting on $100/b oil had to have been ignoring those trends. Again…the market triumphed.

Sister Storms

Is there any greater story of how the markets work than what happened after the one-two punch of Katrina and Rita? The worst disruptions in supply were caused by an externality: the power outages that hit Colonial Pipeline particularly hard. But Colonial got the system back up and running so quickly it earned a citation from the U.S. Department of Transportation and a praise-filled story in The Wall Street Journal.

Beyond that, the market went to work. Traders in Europe and elsewhere put gasoline and other products onto tankers and shipped it on spec to the U.S. Gulf Coast, which is normally akin to exporting corn to Iowa. Crude traders did the same. The U.S. opened its Strategic Petroleum Reserve and couldn't even sell 100% of what it offered. Shocked drivers hit by the spike in prices cut back their purchases. And so on. And yes, high prices lingered for a long time, but that goes back to that 98% capacity utilization figure.

But what would have been the odds that two gigantic storms could hit two separate key regions of the global energy infrastructure within three weeks of each other, and with a few minor exceptions, there wasn't a gasoline line to be found anywhere? Would somebody have taken the other side of that bet?

And then think back to those Chinese gas lines and remember: it will be OK. Just let the market do its stuff. If you don't believe that after the last 16 months, you never will.