Since reading the Wall Street Journal's analysis of the growing disconnection between the industry's West Texas Intermediate (WTI) crude oil benchmark and the actual crudes that refineries purchase and process, I've been pondering this latest version of a fairly old problem. Although current concerns about supply, demand and capacity in the Mid-Continent have made hedging with WTI more problematic than usual, anyone engaged in this sort of risk management--or speculation--must surely understand that the "basis risk" has always been subject to unpredictable swings from local factors, as well as the larger shifts of the global oil market. At the same time, market professionals have been concerned for two decades about the potential for WTI to become irrelevant in a world of disproportionately heavy and sour future oil production.
Although all of my oil trading experience was in the dark ages before the Internet, when orders were placed by phone, rather than on a screen, some aspects of the business haven't changed. As the Journal rightly points out, the physical oil at the heart of WTI trading still represents a shrinking and increasingly unrepresentative sample of global crude oil grades, many of which are heavier and higher in sulfur and other impurities, rendering them harder to refine and thus less valuable. That never stopped crude sellers from pegging their prices to WTI, including the heavier, somewhat more sour Californian and Alaskan crudes I traded in the late 1980s and early 1990s. In hedging San Joaquin Valley Heavy crude with WTI, the basis risk--reflecting the correlation between the price of thing being hedged and the instrument with which it was hedged--could be nearly as large as the total market risk.
The circumstances described in the article are an extreme case of this phenomenon, in which a temporary glut of crude oil in Cushing, OK, the delivery point for the WTI contract, has detached the WTI price from the world price, as represented by the price of Brent Crude from the North Sea. Historically selling at a discount to WTI, Brent is now roughly $2.50/barrel higher, reflecting conditions in the larger market outside Oklahoma. But in assessing whether this is a temporary problem or a long-term shift, it's important to realize that WTI at Cushing, OK isn't quite as stranded or inflexible as the Journal indicates. A quick review of the terms for WTI on the NY Mercantile Exchange shows that a variety of crude oil types can be delivered in satisfaction of the contract, including other sweet crudes from the US, Colombia, Nigeria, Norway and the UK. The contract also provides for an "alternative delivery procedure," which could include other locations besides Cushing. If there's one thing physical oil traders know how to do, it is negotiating location differentials.
Nor is the arbitrage between storage and future delivery quite the permanent feature the author suggests. It only works when the market is in "contango", with future prices higher than current prices, typical of an oversupplied market. But over the long haul, the market is more often in "backwardation", with future prices falling off from current levels. Speculators playing this "front-to-back arb" are exposed to a sudden shift from one state of the market toward the other, and anyone thinking contango is a perpetual motion machine is in for a rude surprise.
So at least part of the problem described by the Journal looks like a transient and a normal part of market risk--another good reason for those who know little about oil fundamentals to forgo dabbling in oil futures. However, this doesn't alter the underlying problem that most of the oil that will be produced in the future will look a lot less like WTI than most of the oil that's already been produced. Explorationists have had a remarkable run for the last 20 years, finding more sweet crude than anyone expected in places like West Africa, the North Sea, and the deep waters of the Gulf of Mexico. But the odds against continuing that streak get worse each year, with the preponderance of global reserves lying in the Middle East, where oil is typically heavier and higher in sulfur and than WTI. The need for a sour crude benchmark similar to what WTI and Brent provide for sweet crudes has existed for a long time, and it will continue to grow.
But here we run into a Catch-22. Launching a new futures contract isn't easy, especially when many of the parties that could provide the liquidity necessary to lure major oil companies and other conservative players into a new market have vested interests in seeing a "sour contract" fail, as NYMEX's previous attempt in the 1980s did. If your firm is making good money writing over-the-counter swaps for illiquid and much less transparently-priced commodities, why would you want to help put this activity out of business by encouraging a transparent, liquid and flexible exchange-traded sour crude contract with low transaction fees? The only thing I see changing this calculus is if the problems at Cushing grow large enough to make the basis risk unmanageable for both sides of the transaction, eroding the profits of market makers, as well as hedgers. The Journal seems to be saying we're at that point, but I've heard that before.
What does this mean to the average person? For starters, it reduces the importance we should place on that part of the media's energy coverage--not that there was much benefit in following day-to-day changes in the WTI price, before. At the same time, investors in the energy sector may want to broaden the indicators they follow, to include more of grades that refineries actually run. That will require a little more legwork. If the new Middle East Sour contracts on the ICE and the Dubai Mercantile Exchange actually take off, that task will be easier.