As US Oil Production Revives, New Vulnerabilities Appear

• The expansion of US oil production is centered in a handful of states, and in particular two whose gains more than offset declines in two former production leaders.
• For various reasons the West Coast has missed out on this revival, straining infrastructure and creating new vulnerabilities that should be addressed.

On the front page of today's Wall St. Journal I see that "US Rises To No. 1 Energy Producer." This news builds on a number of recent headlines such as, "US oil production reaches highest level in 24 years." Stories like these aren't as attention-grabbing as they were when this streak began more than a year ago, once shale oil production ramped up dramatically.  What occurred to me this time, however, was how different the current distribution of US oil output is than it was in the late 1980s.

A handful of states still account for the lion's share of US oil production. Then and now, Texas tops the list, exceeding its 1989 output by 37%. At nearly 2.6 million barrels per day (MBD) in the most recent reported month --140% above at its low point in 2007--its share of US oil production had grown to around 35% by June. However, beneath Texas  the list of top oil states has been jumbled in ways few would have anticipated two decades ago.

Alaska, California and Louisiana, the second-, third- and fourth-ranked producers in 1989, then supplied 41% of total US crude oil output. After decades of decline, the same three states now contribute just 17%, excluding production from the federal waters off Louisiana's coast. Meanwhile, thanks to the development of the Bakken shale, North Dakota has jumped from the number  6 spot just five years ago to number two, eclipsing Alaska early in 2012.  Traditional mid-tier producers like Colorado, Oklahoma and New Mexico are also contributing to the overall US oil revival. This surge of highly productive drilling in roughly the middle third of the country, on top of a million-plus barrels per day from the Gulf of Mexico --mainly from deepwater rigs--has scrambled existing oil transportation arrangements.

When onshore production in Texas and the rest of the mid-Continent shrank in the 1990s and 2000s, the region's pipeline network gradually evolved into the country's principal oil-import conduit. The growth of production in the federal waters of the Gulf of Mexico, which had reached 1.6 MBD at the time of the Deepwater Horizon accident in 2010 but subsequently declined to about 1.2 MBD, meshed well with that model.

Today's big challenge goes against that grain: moving the growing surplus of oil in the upper plains states to markets on the West, Gulf and East Coasts, increasingly by rail. Much of the turbulence we've seen in the US oil market  in the last two years reflects the delays inherent in realigning and expanding that network to accommodate newly abundant domestic supplies.

Yet on the other side of the Rockies, the picture looks very different. When I was trading crude oil for Texaco's west coast refining system in the late 1980s, balancing the crude oil surplus on the Pacific coast required shipping multiple tankers a month of Alaskan North Slope oil to the Gulf, where production was shrinking, and prompted the construction of a new pipeline to send surplus oil to east Texas over land. After two decades of decline from mature fields, along with moratoria on tapping new offshore fields, imports now make up roughly half of west coast refinery supply, even though regional petroleum demand is essentially back to 1989 levels. It remains unclear whether and when California will allow producers to tap the state's potentially game-changing oil resources in the Monterey shale deposit.

Barring further change, the regional nature of these shifts means that the energy security benefits accompanying the revival of US oil production are a party to which the West Coast has not been invited, or has perhaps declined the invitation. That's significant, because it leaves residents of California, Oregon, Nevada and Washington much more exposed to any disruptions in global oil trade, since the existing US Strategic Petroleum Reserve was never intended to provide coverage west of the Rockies. In this light, the appetite of west coast refiners for trainloads of Bakken and Eagle Ford crude looks strategic, rather than just a temporary response to market conditions.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Setting Oil Prices

As the Congress moves ahead with legislation aimed at reducing the contribution of speculation to high oil prices, it's worth taking a moment to reflect on how oil was priced before the influence of the futures markets became so pervasive, or before they even existed. A quick review reveals that any nostalgia for this earlier, simpler era is largely misplaced. Today's oil markets, for all their faults, are models of transparency and efficiency by comparison. Let's hope that our government can discover the right formula for curbing their excesses, without destroying the liquidity and highly-visible price discovery that they provide to producers and consumers, alike.

I've devoted a fair amount of space to the question of oil market speculation. I don't see the signs of a housing or Dot-Com-style bubble, but I also don't dismiss the effect of demand from long-biased asset-class investors on the market. As we often hear from skeptics of the influence of speculation, buyers and sellers must indeed be evenly matched, but higher demand for long futures can only be met by bidding up the price. That tends to drive up the price of the physical commodity bought by refiners, because of the mechanisms by which physical oil is priced. However much this has contributed to pushing oil beyond the $70-$80 per barrel that some industry experts suggest more reasonably fits the market fundamentals, a return to the way oil prices were formerly determined would not guarantee lower prices.

There are many excellent accounts of the history of oil and its pricing, and I can't possibly do justice to this subject in a brief blog posting. If you haven't read the book for which Daniel Yergin won the Pulitzer Prize in 1992, that would be a good place to start. Prior to the first oil crisis, the price of oil was effectively set by the Texas Railroad Commission, which published the monthly quota for production in the state. Together with import restrictions, this constrained supply enough to keep US oil prices between $2 and $4 per barrel. Once the Railroad Commission quota hit 100% in 1971, as a result of growing demand and the peaking of Texas oil output, its influence on prices ended. Oil from the Middle East and other big exporters in that period was sold mainly via long-term contracts, at prices that changed infrequently and that sometimes included "net-back" provisions, explicitly tying the price received by the producer to the revenue realized by refiners in key markets.

All of this changed in the 1970s, after OPEC consolidated its control and began raising the price. It ended net-back discounts and nationalized the holdings of the international oil companies. Between 1972 and 1978, the average price US refiners paid for imported crude oil quadrupled in dollars of the day. The US government intervened in the market by setting the price of "old" and "new" oil--trying to hold down prices while leaving incentives for new domestic production--and limiting imports. These distinctions were exploited by clever traders, and integrated refiners were forced to supply small, independent refiners, even if their own facilities were under-utilized. It was a mess. From 1978-81, in the aftermath of the Iranian Revolution, oil prices increased by another 150%. Over the next few years, OPEC's ability to set prices was eroded by a 10% reduction in global oil consumption and a tsunami of new non-OPEC output from the North Sea, the North Slope and elsewhere. In the ensuing battle for market share, the price of oil fell from its peak of around $40/bbl. to $13, requiring the 1990 Iraqi invasion of Kuwait finally to push it back above $20.

When I traded oil in the late 1980s, most of the US production I dealt with was bought and sold on the basis of the oil companies' posted prices, which solicited offers to sell them lease-level crude output. Alaskan North Slope crude was one of the few domestic grades I handled that was sometimes pegged to the price of West Texas Intermediate crude on the New York Mercantile Exchange (NYMEX.) The prices of the relatively few international cargoes I bought were typically negotiated for each cargo, without reference to other markets. Although I never bought Saudi oil, it was priced by Aramco on two formulas, one for "eastern" and one for "western" destinations. Transparency in that period depended on the ability of reporting services such as Platts to ferret out the details of the transactions that occurred each day. The fewer the transactions, the less reliable these reports were, especially for domestic grades outside the week or so prior to monthly pipeline scheduling, when most deals took place.

History is rarely a perfect guide, but in this case I think it offers some useful lessons concerning how oil might be priced, if the futures markets became less liquid or less influential. Although prices might not be as volatile, day to day, they would be no less prone to manipulation, or to sudden price spikes in response to changes in supply or demand. The pre-NYMEX oil market only yielded low prices when supply was abundant, a characteristic that has been absent since oil prices took off in 2003. Today's problems of transparency, involving the identity and motivation of market participants, pale in comparison to the former challenges of discerning precisely what the day's price was, in the absence of an open, visible exchange platform. I dislike clichés, but as the father of a small child the image of throwing out the baby with the bathwater resonates strongly, here.