Never have supply and demand in petroleum markets diverged more radically than they have in the last year and a half. A tight market in products and crude in late spring 2008—complete with allegations that it was all a speculator- driven frenzy—sank less than a year later into a market where inventories for crude and some grades of products built to levels not seen in more than 25 years. Supply and demand is a word pairing present in all markets, all the time. But in oil markets over the past 18 months, we’ve had other word couplings to describe the trend of the moment. First, we had “diesel dominance.” Then, keeping with the d-based alliteration, we had “demand destruction”. Then we had “price collapse,” followed by price recovery. We also had natural gas depression, and we had political posturing. But for all that wild movement, markets in the next two to three years will be marked by three important questions:

• Can new projects coming online, some of them planned seven or eight years ago, do anything to counter declining flow rates from existing fields, some of them dramatic? Looking beyond that medium-term time frame, can some very recent promising discoveries assure supply for the middle of the next decade and beyond?
• Can the demand destruction in developed countries, the socalled OECD nations, continue apace so that there will be room to supply growing demand from countries such as China, India and Brazil, without setting off a surge in prices?
• In the U.S., can the suddenly abundant supply of natural gas help do something recently thought inconceivable: Act as a restraint on the demand for, and possibly the price of, crude oil and products made from it?

Unpleasant Facts

The decline in demand and the softening in price that accompanied the global economic meltdown helped to mask some unpleasant facts. By midyear 2008, when West Texas Intermediate (WTI) prices peaked at $145.66 a barrel on July 11, the high price reflected some serious imbalances in the supply/demand equation.

For starters, the price of diesel relative to crude—which ultimately is the only way to measure its true strength—was completely out of whack with historical norms. That had been a long time coming, but a combination of Europe’s many tax breaks to encourage diesel consumption, implementation of more stringent sulfur regulations in diesel and the concurrent tightening of supply, and political strife in Nigeria that decreased the flow of dieselrich crudes put U.S. Gulf Coast diesel at a level more than 130% of the price of WTI by early February 2008. At the start of the year, it was closer to 112%. The “diesel dominance” in the complex of petroleum prices seriously undermined the political posturing that argued it was speculators driving the price of oil higher. It’s difficult to speculate on a large scale in physical diesel, and yet, there it was, soaring to unheardof heights and leaving behind the price of crude, which is as much a financial asset as it is an industrial fuel.

That was followed by the sharpest one-year decline in petroleum use ever recorded—the “demand destruction,” as it became known. In 2007, the International Energy Agency (IEA) estimated that world demand for petroleum was 85.82 million barrels per day (b/d). But in early fall 2009, the agency projected that by the end of the year, the average for 2009 would be down to 83.9 million b/d. That would mark the biggest decline since 1982.

Welcome Respite

For consumers of oil, it has been a welcome respite. They watched as prices rose for almost nine years, from unsustainable lows, in inflation-adjusted terms, of $0.95 per gallon in early 1999 all the way to the highs of $4.10 per gallon in 2008, with a relatively brief recession-induced decline early in the decade.

It may be comforting to believe that all of that was the action of speculators—and there are many politicians who want just that—but the prices of last year aren’t surprising in light of just how tight markets gradually became over those eight to nine years.

For example, in July 2008, the U.S. Energy Information Administration said the OPEC’s surplus crude oil production capacity in the third quarter was a mere 1.2 million b/d, all of it in the hands of the Saudis, against a consumption base of more than 86 million b/d … a mere pittance. That same agency 13 months later put the spare capacity at 4.31 million b/d, giving consumers some breathing room should demand turn around.

What’s notable is that even when that gap tightened, demand in major consuming countries—the United States, Japan, etc.—was flat to down. Brazil, China, India and Middle East countries were providing all the positive growth numbers. At the higher level of spare capacity, those trends were still in place, but with sharper demand declines in the developed nations.

The more recent, higher spare capacity figures mask an uncomfortable reality: that bigger cushion was created solely by the decline in global demand, since supply is barely growing.

The way the oil market is balanced is fairly simple: every well around the world pumps full out unless there’s a maintenance shutdown. The exception would be those fields that are in the eleven OPEC countries. OPEC looks at estimated world demand, looks at non-OPEC supply, and tries to fill in the difference by controlling its own production.

Every Last Drop

The lack of spare capacity by mid-2008 essentially meant that OPEC had little to do. That difference between world demand and non-OPEC supply, known as the “OPEC call,” was disappearing non-OPEC countries produced 50.06 million b/d in 2004. By 2007, according to the IEA, that figure had barely risen, to 50.9 million b/d—including 200,000 b/d of biofuels, which doubled from 2004. Non-OPEC output is declining for a variety of reasons in many countries, ranging from accelerating rates of depletion to outright governmental mismanagement of native petroleum resources. The IEA sees the non- OPEC number rising to just under 52 million b/d by the end of 2010, but the agency has consistently overestimated that supply and makes frequent revisions to it, usually to the downside.

That underwhelming performance came as world demand rose from 82.5 million b/d in 2004 up to about 85.8 million b/d in 2007. In essence, non-OPEC nations did nothing to help meet that growing consumption.

The world continues to discover oil, despite steep cutbacks in exploration budgets implemented when prices collapsed. For example, in one three-week period in late August through early September, truly significant discoveries were reported from Iran, Brazil, the U.S. Gulf of Mexico and a new frontier in Sierra Leone.

That’s great for consumers, but are flows from these finds—which are still years off from hitting the market—going to be enough to offset the declining production trends in so many other countries, like Mexico (forecast output of 2.77 million b/d in 2010, down from 3.68 million b/d as recently as 2006) or the United Kingdom (2.93 million b/d in 1999; estimated at 1.37 million b/d for 2010)?

The best solution for the U.S. to this dilemma may be coming from the natural gas market. Tremendous gains have been made in recent years unlocking gas reserves from shale formations in the United States that had been known to exist but had been viewed as not exploitable. With that gas now marketable, Chesapeake Energy—one of the largest shale producers—has become the Pied Piper of a vision in which natural gas moves its way deeper into the U.S. energy picture.

But there’s been a problem with that from the perspective of metals suppliers: natural gas drilling is being reduced because of the low prices created partly by the recession, but also by a glut of natural gas coming from the shale formations.

The Impact on Metals

For metals suppliers, there are two correlations that bear watching.

The first is the very clear, direct relationship between the price, not so much of oil, but of natural gas, and the U.S. rig count. For example, in the fourth week of September, the total Baker Hughes count of operating U.S. rigs was 1,017, with natural gas accounting for 710 of those rigs, and oil providing 297. (A small miscellaneous category accounts for the balance.)

One year earlier, the gas/oil split was 1,559/423. In that year, oil prices fell, but natural gas prices plummeted. And given that natural gas drilling is the backbone of U.S. drilling efforts, it’s easy to see why the relatively healthy oil prices near $70 per barrel in the third quarter of 2009 weren’t disastrous for oil drilling, but natural gas prices that lingered near $3/MMBtu hit natural gas drilling hard. So metals suppliers should be looking to the price of natural gas far more than the price of crude for some direction on likely demand from the upstream part of the drilling business.

The second correlation to watch is the margin that refiners find in the market, as well as demand for their product. That’s the downstream part of the business. Downstream, the prospect is not good. Oil refiners make their money completely on the basis of margins: What does it cost a refiner to buy crude, and what do they get when they sell the products that come from processing the oil?

The most basic barometer of this number is the 3:2:1 crack spread, which measures the difference between the value of crude and the value of the products made from it. Crack spread can be calculated by taking the price of a barrel of NYMEX light sweet crude, multiplying it by three, and subtracting that from the sum of two barrels of NYMEX RBOB, which is a semifinished gasoline product delivered in the New York harbor, and one barrel of NYMEX heating oil, also based in New York harbor. It’s an indicator that has plenty of flaws, but is still seen as an easy-to-calculate way of figuring out the rough health of refining margins.

In the first half of 2008, the 3:2:1 average was $12.55/b. In the second half of the year it sank to $7.61, and in the first almost nine months of 2009, it rose only slightly to $9.80. Neither of those last two numbers is considered particularly healthy.

But even if they were strong, refiners are facing that previously discussed drop in demand. The result? Steep cutbacks in capital spending. For example, Valero, the biggest U.S. refiner, said in August 2009 that it was cutting its capital expenditures to $2.1 billion from the planned $3.5 billion announced in December 2008. Later in September, the company’s president and CEO, Bill Klesse, said unspecified projects slated for construction “past” 2011 and 2012 “will all be delayed.” Delayed along with that construction will be all the normal purchasing of plate, bar and tube that normally accompanies such projects.

John Kingston is the global director of oil at Platts, a division of McGraw-Hill that provides news, analysis and price assessments for oil, natural gas, nonferrous metals, steel and other commodities. See www.platts.com for more information.