America's Crude

Tanks are fed by a maze of pipelines at Cushing, one of the world’s largest storage sites for crude.

T?imes are dark for American oil producers. Companies are still reeling from the extraordinary changes that have hit the industry since summer 2008.

As economists pick apart the continuing collapse of the world’s financial markets, popular opinion is that hedge funds and speculators ran up commodity prices in the heady days that preceded the bust.

?Richard Eckaus, professor emeritus at MIT, says “speculation caused the extraordinarily high oil prices during the first half of 2008.”

Oil and other commodities tied to industrial demand seemed like good bets for investors. Money poured into the commodities markets from individuals, institutional investors, hedge funds, multinational banks and other entities.

Last year, many people believed that the world had reached peak oil, the point at which global production was at its maximum level and future production could only slide downhill. Oil was seen as a finite, depleting resource, and robust economic growth in such nations as China and India meant that Americans and Europeans were simply going to have to pay more for their share of dwindling supplies. A weak U.S. dollar and risks of supply disruptions only exacerbated the pricing scenario.

Richard Eckaus, Boston-based professor of economics emeritus for MIT, analyzed oil prices in spring 2008 and pinned the blame for lofty prices firmly on speculation. “One of the surprises was that the speculative bubble was not so obvious to other people,” he says. “There are good economists who disagreed with me.”

Oil’s price rise began in 2004, after several years of relatively stable levels between $25 and $30 a barrel. Excepting a drop of nearly $20 in 2006, prices marched upward.

?A state-of-the-art control room records data on crude stored and transported to and from Plains All American Pipeline LP’s facilities in Cushing, Oklahoma.

Did demand growth prompt the price rise? Global demand for oil grew sharply from 2002 to 2004, thanks mainly to China’s burgeoning economy. “But since 2005, the rates of growth in world demand and Chinese demand actually fell substantially,” says Eckaus. Annual increases in world oil demand stood at about 1.5%, including China. On its own, Chinese demand growth fell from a peak of more than 16% in 2004 to about 5.3% in early 2008.

Another explanation for the surge in oil prices was the depreciation of the U.S. dollar. “This is an easy argument to dispose of,” says Eckaus. “The U.S. dollar depreciated by about 9% against the euro since 2004, when oil prices began their strong upward move. So it would have taken just a 9% move of the oil price in dollars to have preserved the purchasing price in euros of a barrel of oil. But the price of oil in dollars roughly quadrupled.”

?Manifolds attest to the volumes of crude handled at Plains’ terminal.

Since oil is widely accepted to be a fixed resource, and one that is being depleted, that could lead to towering prices in the face of growing demand. Hotelling’s rule spells out the economic process by which prices of a fixed resource rise due to depletion. Application of this rule shows that actual oil prices were far above what should be expected. Furthermore, near-term shortages due to an inability to produce higher volumes were not a factor. OPEC’s spare capacity was just below 10% in February 2008, a level higher than that seen in 2004, 2005 and most of 2006.

Risk premiums also help determine oil prices. This is a difficult argument to counter, because it’s a subjective assessment. However, Eckaus notes that there were no new, major threats to stability in the oil-producing regions of the Middle East during the spike in oil prices in the first half of 2008.

“After you exhaust the various reasons given for high oil prices, what’s left is speculation.” The elevated prices resulted from a speculative bubble, as investors blew the volume of oil transactions far above what the world needed for ordinary commercial transactions.

“Supply and demand forces do not push prices to increase the way they were increasing in early 2008, absent of dramatic catalysts. And there was nothing dramatic going on in oil supply and demand during that time.”

Changed expectations

?James Smith, professor at Southern Methodist University, says “that oil demand is very sensitive to economic growth.”

Whatever the causes of inflated oil prices, now the bubble has burst. Oil prices are back to levels last touched in 2004, and the world is experiencing a dramatic skid in demand. Changed expectations brought about the great fall, says James L. Smith, Dallas-based professor of economics, Southern Methodist University, and editor of The Energy Journal, published by the International Association for Energy Economics.

Two events triggered that change in perception. The first was consumers’ delayed response as oil prices rose and stayed up for a long time. The lack of conservation in the short term is often seen as a signal that consumers are willing to pay anything.

That’s a delusion. “It takes time for consumers to change their behavior, and it takes time to alter industry consumption of these fuels. After a couple of years, however, people do change.” Behaviors started to change at the same time the recession started—the second factor.

Oil demand is much more sensitive to income level and an economy’s gross domestic product than it is to short-term price fluctuations. “It’s almost one for one. If the economy grows, the demand for oil grows in proportion,” says Smith.

During 2008, the world turned. Confidence in future growth eroded, and then actual shrinkages occurred in the global economy. “People see there is excess production capacity and that puts downward pressure on prices.” As expectations deteriorate, stockpiles are sold to take advantage of current prices, accentuating the sense that a crash is unfolding.

“There is a real physical change, but it’s also the anticipation of a change that causes these price movements in advance.”

Demand off markedly

?John Felmy, chief economist for API, says U.S. oil demand dropped by 1.2 million barrels a day in 2008, to the lowest level in five years.

The slide in demand started slowly and rapidly accelerated. Now it’s gone off a cliff.

“In late 2007 and early 2008, we saw demand for gasoline drop, because consumers were responding to price,” says John Felmy, chief economist for the Washington-based American Petroleum Institute (API).

However, other parts of petroleum demand remained firm during that time, particularly demand for diesel. Indeed, diesel demand was very strong until June 2008, when it suddenly turned downward.

“I view diesel demand as a leading economic indicator,” says Felmy. “It’s reflective of the overall economy, and there is no flexibility in price.” For Felmy, the lapse in diesel use confirmed that the nation was in recession, long before the business-cycle dating committee came to the same conclusion.

“Now it appears that the dominant factor in demand is the economy.”

China’s Olympic Games marked the turning point. Prior to the games, the economies of many nations were growing. Driven by both the Olympics and a severe earthquake, China’s demand was robust. Post-Olympics, demand downshifted, China backed off some of its purchases and its economy began to falter. And so did economies worldwide.

U.S. demand fell sharply, and because the U.S. is such a huge consumer of crude, the magnitude of that decline essentially flattened worldwide petroleum demand growth in 2008.

Last year, according to API, U.S. petroleum deliveries fell 1.2 million barrels a day. The 6% drop from 2007 levels took demand to the lowest point seen since 2003. Gasoline deliveries were down 3.3%; distillate fuel oil, 5.8%; jet fuel, 6.1%; and residual fuel oil, 14%.

Storage tanks at Cushing are nearly full; this year, Plains is expanding its terminal by 1.7 million barrels.

“We saw decline in demand across all major categories last year,” says Felmy.

World demand also slumped in 2008, with further declines expected this year. Daily oil demand in November 2008 in OECD-member countries was 2.8 million barrels lower than that of November 2007. In a recent revision, the Paris-based International Energy Agency has forecast 2009 daily global demand to fall some 500,000 barrels, versus a previously forecast increase of 440,000.

The lesson learned from the wild price swings is that crude price is extremely sensitive to small changes in demand. “There is very low price elasticity of supply, so a small change in demand can lead to a multiple-change impact on price,” says Felmy. If the elasticity of supply is 0.05, a 1% change in demand means a 20-fold change in price.

Supply response

?Richard Nehring, president of Nehring Associates, stands by a portion of the 800-mile-long Trans Alaska Pipeline System. He says U.S. operators have been successfully adding production in many of the nation’s petroleum provinces.

Although demand is the telling factor in oil price, supply can have an impact.

Once, America owned all the oil it cared to use. Great oil fields in California, Texas and Oklahoma poured forth more crude than could be consumed. Those days are past.

But the U.S. remains a formidable, though aging, oil power. Rising prices between 2004 and 2007 had some interesting effects on U.S. proved oil reserves.

“The higher prices stimulated supply, and in some areas the prices had a very significant effect,” says Richard Nehring, president of Colorado Springs, Colorado-based Nehring Associates.

Overall, there was no change in proved reserves in the U.S. between 2004 and 2007, despite steady production throughout that period. “We had a 98% reserve-replacement ratio for crude oil for the whole U.S.,” says Nehring. Proved reserves of crude oil were 21,371 million barrels in 2004 and 21,317 million in 2007, according to the U.S. Energy Information Administration (EIA).

Although the division of oil into conventional and unconventional segments is well known, Nehring proposes an intermediate category of marginal oil resources. The Spraberry trend, the Austin Chalk, and Green River formation oils in the Uinta Basin fall in this category. These resources delivered big reserve gains during the period.

“Rather than from discoveries, the reserve adds are happening in fields with large in-place numbers and low-to-moderate recovery rates,” says Nehring. “Technologies such as horizontal drilling have opened up some very interesting possibilities.”

The Permian Basin posted a reserve-replacement ratio of 155%; the most successful area was District 7c, which is almost all Spraberry trend. “There, we had a reserve-replacement ratio of more than 300%,” he says. “This was not from enhanced oil recovery, but from more intensive development.”

Indeed, producers added nearly 1.5 billion barrels of Permian Basin reserves between 2004 and 2007.

?Samples show the variety of crude oils that have been handled by the Plains All American terminal over the years.

The Rockies also turned in a stellar performance. This region posted a reserve-replacement ratio of 193%, driven by significant volumes of reserves added in Colorado and Utah in such fields as Monument Butte and Altamont-Bluebell. While the Bakken play in North Dakota and Montana has drawn much of the industry’s attention, its performance is actually overshadowed by less publicized plays in the Uinta Basin.

There are also nice reserve-replacement ratios in the coastal regions of California, which posted a 129% ratio. Mississippi was another strong performer, with 140%.

Surprisingly, although the Gulf of Mexico is often considered one of the big new replacement areas, its ratio was less than 50%. Other regions with lagging relative performances were Alaska, California’s San Joaquin Basin and the Midcontinent.

Hand-in-hand with the strong reserve replacement was stabilized U.S. production. Despite hurricanes in the Gulf of Mexico in 2005 and problems with Alaska’s North Slope pipeline system in 2006, national oil production has been flat to very slightly declining at a rate of about 1% a year.

In 2007, U.S. production averaged 5.064 million barrels a day. Last year, daily production dipped below 5 million as a result of declines in Alaska and hurricane shut-ins in the Gulf of Mexico. Absent those shut-ins, Lower 48 oil production would have actually inclined 2% over the prior-year level, however.

Going forward, the U.S. production picture reflects the hard work of the country’s oil producers during the past several years. “In the Lower 48, conventional oil production will be stable to slowly declining,” says Nehring. “U.S. operators have been very successful at applying new technologies and adding production. Alaska is an exception, and is in fairly strong decline.”

And, decent potential for more oil production from marginal reservoirs exists. Current volumes of 300,000 to 400,000 barrels a day from these reservoirs already point the way. “Prices don’t have to recover much from today to be at the level much of these reserve additions occurred at between 2004 and 2007.”

Drilling will have to await that recovery, however.

OPEC’s role

?Valves control flows on individual storage tanks when maintenance or repairs are needed.

The elephant in the room in any talk of U.S. oil demand, supply and prices is OPEC. Demand may be way down and supply may be flat, but oil markets are not free, thanks to the existence of the cartel.

And, the U.S. is a huge importer of crude. In October 2008, the nation bought 10.1 million barrels a day of crude from other countries, including 2.2 million barrels from Persian Gulf nations and 1 million from Venezuela, according to the EIA.

In attempts to shore up crude prices, OPEC has scheduled big production cuts in the past several months. Its deepest cut was slated to be in force in the beginning of January. The cartel’s production capacity is some 33 million barrels a day, and it was producing close to that level in mid-2008. Now it hopes to produce at least 4.2 million barrels less.

“OPEC has been very successful at presenting a united front on announcing these cuts,” says Smith. The first two, in September and October, totaled 2 million barrels a day, and the third, in December, was 2.2 million. At present, the first two cuts are nearly satisfied, but the third, and largest, is not.

Smith’s inclination is to expect OPEC to fail. In the past, the cartel has never overcome its free-rider problem. Members have only fully honored their quotas when they are topped out on production and are physically unable to produce more.

Since OPEC adopted its quota system in 1983, total OPEC production has exceeded the ceiling by 4% on average, but on numerous occasions the excess has run to 15% or more.

At present, individual members heavily depend on making as much money as possible. “For each member, that means producing at maximum levels. I doubt OPEC members are going to rein in production this time, because they have never been able to do it before.”

And, even if OPEC members are holding to the announced cuts, demand has continued to fall. Still more cuts may be required, and each successive cut is more difficult for the producers to adhere to. Additionally, a number of OPEC members have been investing heavily in their upstream production facilities. That seemed to make sense when it appeared that crude oil was in short supply, but it only intensifies the cartel’s challenge of sticking to its quotas.

OPEC’s essential problem is deciding which member will hold most of its excess capacity. Saudi Arabia, typically thought of as the likely candidate, has been hurt as much as the other members by plummeting revenues. “I don’t think Saudi Arabia will absorb all the pain and do all the work of the cartel,” says Smith.

In the trenches

?“E&P companies are basing budgets on very low numbers because they don’t have confidence about the future”, says Ray Deacon, senior analyst with Pritchard Capital Partners.

So, with toppling demand, flat production and a disconcerted cartel, the outlook for U.S. crude producers is grim.

“Right now, the economics for onshore oil plays are so difficult, it’s nearly impossible for companies to plan anything,” says Ray Deacon, New York-based senior E&P analyst with Pritchard Capital Partners. If a company is not hedged, or if it is hedged for only a year or so, most new work doesn’t make sense. Even in secondary and tertiary recovery projects, only a few companies can make money at prices below $50 a barrel.

“Some operators talk about breaking even at $35 a barrel, but to earn reasonable rates of return, crude prices need to be around $52 a barrel.” And that’s at field-level prices, which can be sharply below prices on the Nymex. In the Bakken play, the discount to Nymex is between $8 and $15 a barrel, for instance.

Operators need to cut costs substantially. If costs drop by 30% to 40%, that will help, but costs tend to be sticky on the way down. It will take time for those savings to be realized. At the same time, the cost of capital is rising sharply, which makes it more expensive to get things done.

And, prices absolutely must rise. “Prices are terrible, and may be getting worse. We’re struggling with huge drops in oil demand,” says Deacon.

The tendency is to base budgets on very low numbers because companies don’t have confidence about the future. The one-year forward curve for oil futures was above $70 in November, and currently it’s around $50.

In response to the disheartening outlook, companies that work U.S. conventional oil plays are guarding their cash. Almost all plan to cut activity, and they are determined not to outspend cash flow.

?Pipelines lace through Cushing, the settlement point for WTI on the Nymex.

“This year, very little will get done on the oil side in the U.S., because budgets based on $40 oil don’t allow much activity.” Such long-term projects as the Lower Tertiary play in the Gulf of Mexico will move forward, and there could be some acquisition play among oil-rich names. But the bulk of activity will involve holding onto leases and maintaining production as inexpensively as possible.

“There’s no point in growing if a company can’t prove to investors that it’s accretive to net asset value,” Deacon says.

Even companies that have great projects are capacity constrained, as master limited partnerships have lost the ability to raise capital. Some companies have hedges in place, and they are still fairly protected, but those will come off later this year. By the end of 2009, if prices don’t recover, there will be a lot more distress in the market.

“With prices below levels required for a 10% rate of return, the market is sending a price signal to stop drilling.”

That’s today’s sobering reality for American producers: lay down rigs, cut costs, guard money and wait for demand to rebound.

And take the long view. Certainly, the industry has learned that it’s not sustainable to sell oil for $150 a barrel, but that’s not to say it cannot prosper again.

“Going forward, oil and gas companies should be prepared to prospect at $50 to $60 oil,” says SMU’s Smith. “The era of oil is not over—there’s a lot of oil yet to be produced at those prices, and consumers will always be waiting for it if it’s made available to them.”